ELECTRIC POWER OUTLOOK - PA.GovNERC Reliability Assessment The 2014 Long-Term Reliability Assessment 8 is NERC’s independent review of the 10-year reliability outlook for the North

Electric Power Outlook for Pennsylvania 2014-19 i

ELECTRIC POWER OUTLOOK

FOR PENNSYLVANIA

2014–2019

August 2015

Published by:

Pennsylvania Public Utility Commission

P.O. Box 3265

Harrisburg, PA 17105-3265

www.puc.pa.gov

Technical Utility Services

Paul T. Diskin, Director

Prepared by:

David M. Washko - Reliability Engineer

Pennsylvania Public Utility Commission ii

Executive Summary

Introduction

Section 524(a) of the Public Utility Code (Code) requires jurisdictional electric distribution companies

(EDCs) to submit to the Pennsylvania Public Utility Commission (PUC or Commission) information

concerning plans and projections for meeting future customer demand.1 The PUC’s regulations set

forth the form and content of such information, which is to be filed on or before May 1 of each year.2

Section 524(b) of the Code requires the Commission to prepare an annual report summarizing and

discussing the data provided, on or before Sept. 1. This report is to be submitted to the General

Assembly, the Governor, the Office of Consumer Advocate and each affected public utility.3

Since the enactment of the Electricity Generation Customer Choice and Competition Act,4 the

Commission’s regulations have been modified to reflect the competitive market. Thus, projections of

generating capability and overall system reliability have been obtained from regional assessments.

Any comments or conclusions contained in this report do not necessarily reflect the views or

opinions of the Commission or individual Commissioners. Although issued by the Commission, this

report is not to be considered or construed as approval or acceptance by the Commission of any of

the plans, assumptions, or calculations made by the EDCs or regional reliability entities and

reflected in the information submitted.

Overview

This report concludes that sufficient generation, transmission and distribution capacity exists to reasonably meet the needs of Pennsylvania’s electricity consumers for the foreseeable future.

Regional generation adequacy and reserve margins of the mid-Atlantic will be satisfied through 2024,

provided that planned generation and transmission projects will be forthcoming in a timely manner.

The North American Electric Reliability Corporation (NERC) provided a reliability assessment of the

Regional Transmission Organization, which is PJM Interconnection, LLC (PJM) and concludes PJM

will meet its reserve margin requirements in 2015 of 15.7 percent. NERC projects that PJM will

meet its reserve margin requirements through 2024.

Pennsylvania’s aggregate electrical energy usage (residential, commercial, industrial, sales for resale,

and other) in 2014 was 146,516 gigawatt hours (GWh) versus 146,235 GWh for 2013, which is a 0.2

percent increase in electrical usage. Over the next five years, total Pennsylvania electric energy

usage is projected to increase at an average annual rate of 0.44 percent. This includes a decrease in

average annual residential usage of 0.01 percent, a decrease in average annual commercial usage of

0.03 percent, and an increase in average annual industrial usage of 1.32 percent.

1 See 66 Pa. C.S. § 524(a).

2 See 52 Pa. Code §§ 57.141—57.154.

3 See 66 Pa.C.S. § 524(b).

4 66 Pa.C.S. §§ 2801—2812.

Electric Power Outlook for Pennsylvania 2014-19 iii

Contents

Section 1 – Regional Electric Outlook

Purpose .................................................................................................................................. 1

Regional Reliability Organizations ...................................................................................... 1

North American Electric Reliability Corporation .................................................... 1

NERC Reliability Assessment ................................................................................... 2

ReliabilityFirst Corporation ..................................................................................... 4

Regional Transmission Organizations ................................................................................. 4

PJM Interconnection ................................................................................................. 5

PJM Pennsylvania Regional Transmission Line Expansion Plan Overview ...................... 8

Status of PJM Backbone Transmission Lines ...................................................................... 9

Section 2 – Pennsylvania Electric Outlook

Electric Distribution Companies .......................................................................................... 11

Alternative Energy Portfolio Standards ............................................................................... 13

Energy Efficiency and Conservation Program (Act 129) .................................................... 15

Statewide Review of Electrical Energy Usage ..................................................................... 18

Summary of Data for the Seven Largest EDCs .................................................................... 22

Duquesne Light Company ......................................................................................... 22

Metropolitan Edison Company ................................................................................. 24

Pennsylvania Electric Company ............................................................................... 26

Pennsylvania Power Company ................................................................................. 28

West Penn Power Company ...................................................................................... 30

PECO Energy Company ............................................................................................ 32

PPL Electric Utilities Corporation ........................................................................... 34

Summary of Data for the Four Smallest EDCs .................................................................... 36

Citizens’ Electric Company ....................................................................................... 36

Pike County Light & Power Company ..................................................................... 37

UGI Utilities Inc.—Electric Division ........................................................................ 38

Wellsboro Electric Company .................................................................................... 39

Appendix A – Data Tables Actual and Forecast Data Tables ......................................................................................... 40

Appendix B – Plant Additions and Upgrades Status of Pennsylvania’s Plant Additions and Upgrades .................................................... 48

Appendix C – Existing Generating Facilities Pennsylvania’s Existing Electric Generating Facilities ...................................................... 54

Electric Power Outlook for Pennsylvania 2014-2019 1

Section 1 – Regional Electric Outlook

Purpose

The Electric Power Outlook for Pennsylvania 2014-2019 discusses the current and future electric

power supply and demand situation for the 11 investor-owned jurisdictional electric distribution

companies (EDCs) operating in the state and the entities responsible for maintaining the reliability

of the bulk electric supply system within the region that encompasses the state.

Pursuant to Title 66, Pennsylvania Consolidated Statutes, Section 524(b), the PUC annually

submits this report to the General Assembly, the Governor, the Office of Consumer Advocate and

affected public utilities. It also is posted on the Commission’s website.5

The information contained in this report includes highlights of the past year, as well as EDCs'

projections of energy demand and peak load for 2015-19. The state’s seven largest EDCs6

represent over 95 percent of jurisdictional electricity usage in Pennsylvania. Accordingly,

information regarding the four smaller EDCs contained in this report is limited. The report also

provides a regional perspective with statistical information on the projected resources and

aggregate peak loads for the region that impacts Pennsylvania.

As permitted under the Section 2809(e) of the Public Utility Code, the Commission has adopted

revised regulations, reducing from 20 years to five years the reporting requirements and the

reporting horizon for energy demand, connected peak load and number of customers. Because of

deregulation, information regarding generation facilities, including capital investments, energy

costs, new facilities and expansions of existing facilities, are no longer required. The Commission

relies on reports and analyses of regional entities, including the ReliabilityFirst Corporation and

PJM, to obtain a more complete assessment of the current and future status of the electric power

supply within the region. Also, data for the report is submitted annually by EDCs, pursuant to the

Commission's regulations.7 Sources also include data submitted by regional reliability councils to

the NERC, which is subsequently forwarded to the U.S. Energy Information Administration (EIA).

Regional Reliability Organizations

In Pennsylvania, all major EDCs are interconnected with neighboring systems extending beyond

state boundaries. These systems are organized into regional reliability councils responsible for

ensuring the reliability of the bulk electric system.

North American Electric Reliability Corporation

The North American Electric Reliability Corporation (NERC) has been granted legal authority by

the Federal Energy Regulatory Commission (FERC) to enforce reliability standards, and make

5 This report is available at http://www.puc.pa.gov/utility_industry/electricity/electric_reports.aspx.

6 Those EDCs with at least 100,000 customers.

7 See 52 Pa. Code §§ 57.141—57.154.

Pennsylvania Public Utility Commission 2

compliance with those standards mandatory. NERC oversees the reliability of the bulk power

system that provides electricity to 334 million people, has a total demand of over 830 gigawatts

(GW), has about 211,000 miles of high-voltage transmission lines (230,000 volts and greater), and

represents more than $1 trillion worth of assets.

NERC’s members operate in eight regional reliability entities. Members include investor-owned

utilities, federal and provincial entities, rural electric cooperatives, state/municipal and provincial

utilities, independent power producers, independent system operators, merchant electricity

generators, power marketers and end-use electricity customers. The membership accounts for

virtually all the electricity supplied in the United States, Canada, and a portion of Baja California

Norte, Mexico. The regional entity operating in Pennsylvania is ReliabilityFirst Corporation.

NERC establishes criteria, standards and requirements for its members and all control areas. All

control areas must operate in a seamless and stable condition to prevent uncontrolled system

separations and cascading outages caused by any single transient event.

NERC Reliability Assessment

The 2014 Long-Term Reliability Assessment8 is NERC’s independent review of the 10-year

reliability outlook for the North American bulk power system (BPS) while identifying trends,

emerging issues, and potential risk. Also reported is insight on resource adequacy and operating

reliability, as well as an overview of projected electricity demand growth for individual

assessments areas. NERC also provides specific review of the PJM Regional Transmission

Organization (RTO).

In the 2014 assessment, NERC identifies the following key issues for the North American bulk

power system:

Resources are sufficient to meet reliability targets in most areas in the 10-year review

period.

Reserve Margins in several Assessment Areas are trending downward, despite low load

growth. The PJM baseline reserve margin is set at 15.7 percent and the PJM region is

projecting actual reserve margins in 2015 of about 26 percent, about 20 percent in 2019,

and about 16 percent in 2024.

Environmental regulations create uncertainty and require assessment. Increasing costs

for compliance with environmental regulations are expected to cause accelerated

retirement of fossil-fired generation. Coal-fired power plants are especially vulnerable to

the impacts of the competitive fuel market since low natural gas prices tend to set the

price for electricity on the wholesale market making coal generating units less

dispachable.

8 See NERC, 2014 Long-Term Reliability Assessment, Dec. 2014 available at

http://www.nerc.com/pa/RAPA/ra/Reliability%20Assessments%20DL/2014_LTRA_FINAL.pdf.


A changing resource mix requires new approaches for assessing reliability. North

America’s resource mix is undergoing a significant transformation at an accelerated pace

with ongoing retirements of fossil-fired and nuclear capacity and growth in natural gas,

wind, and solar resources. This shift is caused by several drivers, but primarily by

existing and proposed federal, state, and provincial environmental regulations. Other

drivers include lower natural gas prices due to abundant supply, along with policies

incentivizing the movement from conventional energy resources toward ongoing

integration of both distributed and utility-scale renewable resources. The convergence of

these resource mix changes is directly impacting the behavior of the North American

bulk power system. These developments will have important implications on industry

planning and operations, as well as how NERC assesses reliability.

In addition, NERC performed an analysis of the January 2014 polar vortex event9. The 2014

polar vortex involved extended periods of extreme cold weather from Jan. 6–8, 2014, in several

parts of North America, presenting challenges for system operators in both the Eastern and Texas

Interconnections. During the event, the BPS was stressed with high periods of demand,

establishing new records for several areas. Concurrently, an increased number of units

experienced forced outages amounting to over 10,000 MW, resulting in the use of emergency

operating procedures and calling DR programs in several areas. Despite these extreme

conditions, the BPS remained stable and generally performed reliably throughout the duration of

the event, primarily because of preparation efforts prior to the cold snap. Specifically, generator

owners took preemptive steps to prepare equipment for the freezing temperatures. These steps

included:

cancelling scheduled generator outages

installing additional insulation

testing dual-fuel capabilities

Similarly, system operators coordinated with neighboring areas to ensure resource availability

and share other pertinent information. Subsequent to a thorough review of the event, NERC

released the Polar Vortex Review report in September 2014, based on data and information

provided from the NERC Generator Availability Data System (GADS), as well as supplemental

support from the impacted Assessment Areas. An analysis of this data by NERC concluded that

forced outages during the event were primarily caused by the following:

Inoperable equipment in extreme low temperatures

Unavailability of fuel at generating units (due to supply or transportation or a

combination of both)

Challenges for some dual-fuel capable units in switching from a primary to a secondary

fuel.

9 See NERC, Polar Vortex Review, Sep. 2014, available at

http://www.nerc.com/pa/rrm/January%202014%20Polar%20Vortex%20Review/Polar_Vortex_Review_29_Sept_2014

_Final.pdf.

http://www.nerc.com/pa/rrm/January%202014%20Polar%20Vortex%20Review/Polar_Vortex_Review_29_Sept_2014_Final.pdf

http://www.nerc.com/pa/rrm/January%202014%20Polar%20Vortex%20Review/Polar_Vortex_Review_29_Sept_2014_Final.pdf


NERC also noted that colder temperatures contributed to higher electricity demand while also

increasing the demand for natural gas used for residential heating in some parts of North

America. These conditions stressed the ability of pipeline operators and suppliers to deliver

natural gas to the power sector, which resulted in a significant amount of gas-fired generation

being unavailable due to gas curtailments. This was particularly relevant considering that gas-

fired units accounted for approximately 40 percent of the generation mix during the 2014 polar

vortex. Accordingly, natural-gas-fired units were also the most impacted compared to other

generators, representing over 55 percent of all forced outages during the event.

ReliabilityFirst Corporation

ReliabilityFirst Corporation (RFC), headquartered in Fairlawn Ohio, is one of eight NERC

regional entities serving North America, and is the regional reliability entity for Pennsylvania. Its

service territory consists of more than 72 million people in a 238,000 square-mile area covering all

of New Jersey, Delaware, Pennsylvania, Maryland, District of Columbia, West Virginia, Ohio,

Indiana and parts of Michigan, Wisconsin, Illinois, Kentucky, Tennessee and Virginia. Its

membership includes load-serving entities, RTOs, suppliers and transmission companies.

The RFC controls reliability standards and enforcement by entering into delegation agreements

with regional entities to ensure adequate generating capacity and transmission. Some performance

factors considered in establishing acceptable reliability levels include load characteristics, load

forecast error, scheduled maintenance requirements, and the forced outage rates of generating

units. The RFC reliability standards require sufficient generating capacity to be installed to ensure

the probability of the system load exceeding available capacity is no greater than one day in 10

years. Load-serving entities that are members of RFC have a capacity obligation determined by

evaluating individual system load characteristics, unit size and operating characteristics.

Regional Transmission Organizations

The two RTOs within the RFC footprint are PJM Interconnection, LLC (PJM) and Midcontinent

Independent System Operator, Inc (MISO).


PJM Interconnection

PJM is a regional transmission organization that ensures the reliability of the largest centrally

dispatched control area in North America, covering 234,417 square miles. PJM coordinates the

operation of 183,600 megawatts (MW) of generating capacity with 165,492 MW peak demand and

more than 62,556 miles of transmission lines. The

PJM RTO coordinates the movement of electricity

through all or parts of Delaware, Illinois, Indiana,

Kentucky, Maryland, Michigan, New Jersey, North

Carolina, Ohio, Pennsylvania, Tennessee, Virginia,

West Virginia and the District of Columbia.10

PJM manages a sophisticated regional planning

process for generation and transmission expansion to

ensure the continued reliability of the electric system.

PJM is responsible for maintaining the integrity of

the regional power grid and for managing changes

and additions to the grid to accommodate new

generating plants, substations and transmission lines.

In addition, PJM analyzes and forecasts future electricity needs of the region. Its planning

process ensures that the electric system growth is efficient and takes place in an orderly fashion.

PJM also supports market innovation through its active support for demand response markets for

energy, capacity and ancillary services, and helps ensure that appropriate infrastructure and

operational capabilities are in place to support newly installed renewable energy facilities.

PJM coordinates the continuous buying, selling and delivery of wholesale electricity through

robust, open and competitive spot markets. PJM balances the needs of suppliers, wholesale

customers and other market participants, and continuously monitors market behavior. In 2014, the

PJM market grew by 32 percent from $34 billion in 2013 to $50 billion in 2014. Membership

increased 7.5 percent from 879 members in 2013 to 945 members in 2014.11

PJM’s 2014

transmission volumes were 838 terawatt hours (TWhs), compared with 834 TWhs for 2013.

10

See PJM 2014 Annual Report, available at http://www.pjm.com/~/media/about-pjm/newsroom/annual-reports/2014-

annual-report.ashx. 11

Id.

Figure 1 PJM RTO service territory


PJM exercises a broader reliability role than that of a local electric utility. PJM system operators

conduct dispatch operations and monitor the status of the grid over a wide area. NERC provided a

PJM reliability assessment that concludes PJM will meet its reserve margin requirements in 2015

of 15.7 percent. NERC projects that PJM will meet its reserve margin requirements through

2024. Continued use of the PJM Reliability Pricing Model (RPM) will ensure that the planning

reserve margin is met. The NERC projections for the reserve margins for PJM range from 26

percent in 2015 to 16 percent in 2024. The demand growth forecast for PJM has decreased to 0.9

percent from last year’s projection of 1.3 percent. PJM 2015 forecast modeling was changed to

factor in the magnitude of change of energy efficiency gains that were previously not effectively

considered.

There were 27 generators deactivated in 2014 totaling 2,966 MW of generation with and 2,745

MW of pending deactivation requests scheduled between 2015 and 2020. To replace retiring

generators, there are over 21,000 MW of new generating resources under construction as of

December 31, 2014 and an additional 41,800 MW actively under study.

Effect of the January 2014 Polar Vortex

In January, sustained arctic temperatures – known as the “polar vortex”– tested the limits of

reliability in the PJM system. It was a vivid reminder that weather threats to the region’s electric

grid are not limited to the heat and humidity of summer. The impacts of the polar vortex on the

system were extensive and included:

Eight of the 10 highest winter peaks PJM had experienced up until that time occurred in

January 2014.

Peak Demand was 20,000 to 30,000 MW higher than during a typical January.

On January 7, when the PJM region reached new all-time winter peaks, more than 40,000

MW of generating capacity failed to be available amounting to 22 percent of system

capacity and 30,000 megawatts more than expected.

Despite these challenges, PJM and their members maintained reliability throughout the month with

limited emergency procedures and voluntary demand response. PJM analyzed the system’s

performance during the polar vortex and shared their findings with member companies, Congress,

regulators and state legislators. Although power continued to flow without interruption on the high-

voltage transmission system, there was an unusually high rate of outages among generators,

problems with natural gas deliveries for certain power plants, significant pricing impacts, and

inflexible unit-scheduling conditions. PJM’s experience with the polar vortex reinforced their

efforts to ensure reliability, especially with the added challenge of the unprecedented fuel transition

underway in PJM and across the United States. Since 2009 and by 2019, more than 23,000 MW of

coal-fired generation in the PJM region is expected to have retired because of age, stricter

environmental regulations and the influx of new, more efficient gas-fired generators fueled by low-

priced shale gas. This rapid shift from coal to gas generation has led to the retirement of base-load

generating capacity and heavier reliance on winter natural gas markets.


PJM implemented lessons learned from the polar vortex event that included more testing of

generating equipment in advance and refining operating procedures, both of which will contribute

to improved coordination with the gas pipeline industry. Additional improvements included a

formalized gas commitment process for long-lead-time generation and provisions for generators to

change cost schedules within a single day to reflect their costs more accurately. Voluntary testing

was implemented for generation that had not run for an extended period; generating units also were

required to perform a pre-winter checklist of items aimed at improving overall winter readiness.

To improve gas/electric coordination over the long term, the FERC considered rules that would

bring the timing of the markets and operating days of the gas and electricity industries closer

together. Scheduling and operating day differences between the natural gas and electricity

industries cause inefficiencies in both markets, creating a reliability concern because of the

growing use of natural gas in power generation. Additionally, the Eastern Interconnection

Planning Collaborative is conducting a broad-based Department of Energy-funded study of natural

gas infrastructure and its ability to serve the electricity industry. PJM, ISO New England, the New

York Independent System Operator, the Midcontinent Independent System Operator, the

Tennessee Valley Authority and Ontario’s Independent Electric System Operator are partners in

the study. The results will be used to inform the planning process of each of the grid operators.12

12

Id.


PJM Pennsylvania Regional Transmission Expansion Plan Overview

The Pennsylvania electric power outlook generally reflects the projections of RFC, which are

based on forecasts of PJM and MISO. We look to regional data concerning the current and future

condition of the bulk electric system because it is planned on a regional rather than state basis.

While the aggregate load for the state’s consumers can be determined, the availability and mix of

electrical generation units cannot be predicted since the complexities of a changing free market

will be the primary driving force.

An RTO such as PJM has the primary responsibility to coordinate and plan future upgrades and

expansion of the regional transmission system. A key part of the planning process is to evaluate

both generation interconnection and merchant transmission interconnection requests. Although

transmission planning is performed on a regional basis, most upgrades and expansion in

Pennsylvania are planned to support the local delivery system and new generating facilities.

Load-serving entities (LSE)13

acquire capacity resources by: entering bilateral agreements,

participating in the PJM-operated capacity market, owning generation, and/or pursuing load

management options. The PJM generator interconnection process ensures new capacity

resources satisfy LSE requirements to reliably meet their obligations.

All new generation that anticipates interconnecting and operating in parallel with the PJM

transmission grid and participating in the PJM capacity and/or energy markets must submit an

interconnection request to PJM for technical evaluation and approval.

Proposed new generating plants and increased capacity of existing plants in Pennsylvania total

14,015 MW. These facilities are under active study by PJM. Natural gas projects make up more

than 10,307 MW of this queued capacity. This additional capacity may be used to serve

Pennsylvania or out-of-state customers.14

Appendix B lists the current PJM interconnection

requests for new generating resources in Pennsylvania. The existing generating capacity in

Pennsylvania totals 42,628 MW.15

Appendix C lists existing generation facilities in

Pennsylvania.

Peak summer load growth rates for the Transmission Owner zones within Pennsylvania are

expected to range from 0.4 percent to 1.8 percent over the 10 years through 2024. Peak winter

load-growth rates are expected to range between 0.4 and 1.8 percent on average over the same

time period. Forecasted summer peak loads are modeled in power flow studies used in PJM’s

2013 Regional Transmission Expansion Plan (RTEP) studies. PJM’s RTEP includes baseline

transmission upgrades in Pennsylvania to meet expected near-term 2019 peak load conditions.

13

A Load Serving Entity (LSE) is any entity (or the duly designated agent of such an entity), including a load

aggregator or power marketer that (a) serves end-users within the PJM Control Area, and (b) is granted the authority

or has an obligation pursuant to state or local law, regulation or franchise to sell electric energy to end-users located

within the PJM Control Area.(definition from PJM.com glossary) 14

See PJM 2014 RTEP, available at http://www.pjm.com/documents/reports/rtep-documents/2014-rtep.aspx. 15

Data reported to SNL and received by PUC staff on Aug 2015.


RTEP studies also assess anticipated needs for additional transmission expansion plans to meet

long-term load growth requirements through 2029.16

PJM conducts reliability studies to identify RTEP baseline upgrades needed to resolve all

identified reliability criteria violations. PJM cannot compel a generator to operate, but can make

financial arrangements with a generator to continue operating for reliability.

PJM’s recommendation to the PJM Board in December 2014 encompassed a set of 22 projects to

address 56 flowgate violations. They included several line reconductor projects, replacement of

existing transformers with larger transformers, upgrades to terminal equipment on existing

facilities and circuit breaker replacements. As part of its evaluation, PJM considered 15-year

analysis results when developing this set of recommendations to determine if a more robust

solution could be justified. That analysis did not yield such a need. All 22 recommended projects

were upgrades to existing facilities. Two other sets of proposals depend on the ultimate status of

pending deactivations and, separately, planned interconnections.17

In 2014, the Reliability Pricing Model (RPM) auction produced an adequate amount of resources

to serve the PJM region in the June 1, 2017 to May 31, 2018 delivery year. The total capacity

procured in the auction was 167,004 MW, which represents a 19.7 percent reserve margin. A total

of 10,975 MW of demand response was procured, which is a decrease of about 1,433 MW from

last year’s auction. However, there was a significant shift to the types of demand resources that

have more flexibility and a greater contribution to reliability. There were 1,401 MW of more

“annual” and 4,693 MW of “extended summer” demand resources (DR) clearing in this auction

than last year, while the amount of “summer-only” demand resources declined by 7,527 MW since

last year. Energy efficiency continues its growth trend in PJM’s capacity auctions. This year, a

record 1,339 MW of energy efficiency was procured in the auction, which is an increase of 222

MW from last year’s auction.18

Status of PJM Backbone Transmission Lines19

PJM’s 2019 study year power flow base case modeled all transmission upgrades expected to be in

service by June 1, 2019 as approved by the PJM Board through Dec. 31, 2014 or submitted as

supplemental upgrades. The current status of backbone transmission upgrades is summarized

below.

Susquehanna-Roseland 500 kV Line

Approved by the PJM Board in June 2007, the Susquehanna-Roseland 500 kV line (Susquehanna-

Lackawanna-Hopatcong-Roseland) has a required in-service date of June 1, 2012. Regulatory

process delays have pushed the expected in-service out to June 1, 2015. The line was approved by

16

See PJM 2014 RTEP, available at http://www.pjm.com/documents/reports/rtep-documents/2014-rtep.aspx. 17

See PJM 2014 RTEP, Book 5, Section 2.0.2 available at http://www.pjm.com/documents/reports/rtep-

documents/2014-rtep.aspx. 18

See PJM News Release, May 23, 2014, available at http://www.pjm.com/~/media/about-pjm/newsroom/2014-

releases/20140523-pjm-capacity-market-secures-new-and-diverse-resources-to-meet-future-electricy-demand.ashx 19

See PJM 2014 RTEP, Book 2, section 2.0.2 available at http://www.pjm.com/~/media/documents/reports/2014-

rtep/2014-rtep-book-2.ashx


the Pennsylvania Public Utility Commission in February 2010 and by the NJ BPU in April 2010.

The line received final approval from the National Park Service (NPS) who issued a Record of

Decision on October 2, 2012, affirming the route chosen by PP&L and PSE&G; the NPS issued a

Special Use (Construction) Permit on Dec. 12, 2012. The Hopatcong-Roseland portion of the line

was energized on March 31, 2014. The Susquehanna- Lackawanna portion of the line was

energized on Sept. 23, 2014. The remainder of the line is expected to be placed in service by June

1, 2015.

Cloverdale-Lexington 500 kV Line

In October 2013, the PJM Board approved PJM’s upgrade recommendation to reconductor the

AEP portion of the Cloverdale-Lexington 500 kV line, including replacement of eleven tower

structures. This follows December 2011 PJM Board approval to reconductor the Dominion portion

of the Cloverdale-Lexington 500 kV circuit to resolve NERC criteria Category C N-1-1 violations.

AEP and Dominion have coordinated plans underway to rebuild their respective portions of the 44-

mile line in order to increase its operational limit. The Virginia State Corporate Commission

released its final order approving Dominion’s 7.4-mile portion of the line on Sept. 7, 2012.

Dominion began construction in late spring of 2013 with completion in December 2013. AEP filed

its application to reconductor their 37.1-mile portion of the line in late 2013 with an expected

completion date of June 1, 2016.

Dooms-Lexington 500 kV Line

Dominion filed an application with the Virginia State Corporate Commission on Nov. 19, 2012.

On May 16, 2013 the SCC granted a Certificate of Public Convenience and Necessity (CPCN)

authorizing the rebuild project. The project is expected to be completed by 2016.

Mount Storm-Doubs 500 kV Line

The PJM Board approved the rebuild of the Mount Storm-Doubs line in October 2010 with a

required in-service date of June 2020. The Virginia State Corporation Commission issued a CPCN

for the line on Sept. 1, 2011. The West Virginia PSC issued a ruling on December 16, 2010 that the

project is an ordinary extension of an existing system in the usual course of business and does

require a CPCN. The Maryland PSC issued a CPCN on July 7, 2013. The project is under

construction with an expected in-service date by June 1, 2015.

Surry-Skiffes Creek 500 kV Line

The PJM Board approved the rebuild of the Mount Storm-Doubs line in April 2012 with a June 1,

2015 required in-service date for the 500 kV portion of the project and a June 1, 2016 required in-

service date for the 230 kV portion of the project. The Virginia State Corporation Commission

approved Dominion’s request to build the project on Nov. 26, 2013. Construction activities are

underway.

Loudoun-Brambleton Area

PJM’s RTEP includes two 500 kV projects in this area. First, a project that encompasses a rebuild

of the Mosby-Brambleton-Pleasant View- Goose Creek portion of the Loudoun-Doubs 500 kV line

as approved by the PJM Board in October 2011. The project is expected to be completed by

Dominion by June 1, 2016. PJM’s RTEP also includes a new, second 500 kV line from Loudoun


to Brambleton, as approved by the PJM Board in December 2013. This new line is expected to be

in service by June 1, 2018.

Northern New Jersey 345 kV Upgrades (Bergen to Linden Corridor Upgrade Project)

This series of transmission facility line upgrades from 138 kV to 345 kV in northern New Jersey

was approved by the PJM Board in December 2013 with a required in-service date of June 2015.

According to PSE&G, Phase 1 of the project will focus upon work to be performed within the

PSE&G Hudson-Bergen/Marion-Bergen 230 kV and 138 kV overhead transmission corridor and

the Bergen, North Bergen, Homestead, Penhorn and Marion stations. Construction of Phase 1 is

expected to commence in the third quarter of 2015, with an anticipated in-service date of June

2016. Phase 2 will focus upon work to be performed within the PSE&G Linden-Bayway 138 kV

overhead transmission corridor, and the Linden and Bayway stations, with an anticipated in-service

date of June 2017. Phase 3 will focus on work to be performed upon the facilities interconnected

by underground cable, looping together the Bayway, North Avenue, Newark Airport, Bayonne and

Marion stations, with an anticipated in-service date of June 2018. The underground system will

serve to loop together the facilities upgraded in Phase 1 and Phase 2 of the project. Source:

https://www.pseg.com/.

Byron-Wayne 345 kV Line (Grand Prairie Gateway)

The Byron-Wayne 345 kV line was approved by the PJM Board in October 2012, with a requested

in-service date of June 1, 2017. The Illinois Commerce Commission (ICC) issued ComEd a CPCN

on Oct. 22, 2014, authorizing ComEd to construct, operate and maintain the Grand Prairie

Gateway Project. Other permits or approvals from other federal, state and local entities may be

required for the construction of the project, such as a wetland permit from the U.S. Army Corps of

Engineers. ComEd will obtain all required permits in advance of construction and continue

coordinating with agencies, as required, during and after construction. ComEd is preparing for

right-of-way acquisition along the approved route. Construction is anticipated to start as early as

the summer of 2015 and is scheduled to be in service in June 2017.

Section 2 – Pennsylvania Electric Outlook

Electric Distribution Companies

Eleven EDCs currently serve the electricity needs of the majority of Pennsylvania's homes,

businesses and industries. Cooperatives and municipal systems provide service to several rural and

urban areas. The 11 jurisdictional EDCs are:

Citizens' Electric Company

Duquesne Light Company

Metropolitan Edison Company (FirstEnergy)

Pennsylvania Electric Company (FirstEnergy)

Pennsylvania Power Company (FirstEnergy)

PPL Electric Utilities Corporation

PECO Energy Company (Exelon)

https://www.pseg.com/


Pike County Light & Power Company (Orange & Rockland Utilities Inc.)

UGI Utilities Inc. – Electric Division

Wellsboro Electric Company

West Penn Power Company (FirstEnergy)

Figure 2 Map of EDC Service Territories

Each LSE is responsible to make provisions for adequate generating resources to serve its

customers. The local EDC or Commission-approved alternative default-service provider (DSP)

must acquire electricity, pursuant to a Commission-approved competitive procurement process, for

customers who (1) contract for electric power, including energy and capacity, and the chosen

electric generation supplier (EGS) does not supply the service or (2) do not choose an alternate

supplier.20

Under current law, the default service prices for electric generation service are required

to be based upon a “prudent mix” procurement strategy that will produce the least cost to

customers over time.21

20

66 Pa. C.S. § 2803. 21

See id. § 2807(e)(3).


Alternative Energy Portfolio Standards

The PUC continues to implement procedures and guidelines necessary to carry out the

requirements of the Alternative Energy Portfolio Standards Act (AEPS) of 2004 (Act 213).22

Act

213 requires that an annually increasing percentage of electricity sold to Pennsylvania retail

customers be derived from alternative energy resources. The amount of electricity to be supplied

by alternative resources increases to a total of 18 percent by 2021. In 2008, the Commission

adopted regulations pertaining to the AEPS obligations of EDCs and EGSs.23

AEPS resources

must be located in PJM.

Alternative energy resources are categorized as Tier I and Tier II resources. Tier I resources

include solar, wind, low-impact hydropower, geothermal, biologically derived methane gas, fuel

cells, biomass (including electricity generated in Pennsylvania utilizing by-products of the pulping

process and wood manufacturing process, including bark, wood chips, sawdust and lignins in spent

pulping liquors)24

and coal mine methane. Tier II resources include waste coal, demand side

management, distributed generation, large-scale hydropower, by-products of wood pulping and

wood manufacturing, municipal solid waste, and integrated combined coal gasification technology.

Act 213 requires that by 2021, 8 percent of the electricity sold in each EDC service territory will be

derived from Tier I resources, including solar. Energy derived from Tier II resources is to increase

to 10 percent. Act 213 sets forth a 15-year schedule for complying with its mandates, as shown in

Table 1. Since Jan. 1, 2011, all EDCs and EGSs have been required to comply.

Table 1 Alternative Energy Portfolio Standards

22

Alternative Energy Portfolio Standards Act, effective Feb. 28, 2005; 73 P.S. §§ 1648.1—1648.8. 23

See Docket No. L-00060180; 52 Pa. Code §§ 75.61-75.70. 24

See 66 Pa.C.S. § 2814(b).


To meet the requirements of Act 213, EDCs and EGSs acquire alternative energy credits (AECs) in

quantities commensurate to the required tier percentage and the electricity sold to retail customers.

AECs are separate from the electricity that is sold to customers. An AEC represents one megawatt

hour (MWh) of qualified alternative electric generation or conservation, whether self-generated,

purchased along with the electric commodity, or purchased separately through a tradable

instrument.25

AECs are earned when a qualified facility generates 1,000 kilowatt-hours (kWh) of electricity

through either estimated or actual metered production. An AEC is a tradable certificate that

represents all the renewable energy benefits of electricity generated from a facility. An AEC can

be sold or traded separately from the power. AECs are generally purchased by EDCs and EGSs in

order to meet the percentages required under AEPS for any given year. AECs can be traded

multiple times until they are retired for compliance purposes. An AEC can only be retired once

and may not be used to satisfy any other obligations, whether voluntarily or mandated by a

renewable energy portfolio standard in another state.

Clean Power Markets Inc. (CPM) serves as the AEC program administrator for Pennsylvania.

CPM has been administering the program since 2007 and will continue in that role under its

current contract through 2015. In May 2015, the Commission issued a request for proposals for

the next program administrator contract. This contract will be effective until December 31, 2018,

and includes two options for one year extensions. The AEC program administrator verifies that

EGSs and EDCs are complying with the minimum requirements of Act 213. PJM EIS’ Generation

Attribute Tracking System (GATS) is the alternative energy credit registry used to track alternative

energy credit creation and transfer among qualified alternative energy systems. GATS is used by

EDCs and EGSs to verify compliance with the requirements of Act 213.

Under Act 213, the Commission adopted regulations promoting onsite generation by customer-

generators using renewable resources and eliminating barriers that may have previously existed

regarding net metering.26

The regulations also provide for metering capabilities that will be

required and a compensation mechanism that reimburses customer-generators for surplus energy

supplied to the electric grid.27

Act 35 of 2007 amended Act 213. One aspect of Act 35 altered the

reconciliation mechanism used to compensate resellers for surplus energy supplied through net

metering.28

The Commission also adopted regulations that govern interconnection for customer-generators.

The regulations strive to eliminate barriers which may have previously existed with regard to

interconnection, while ensuring that interconnection by customer-generators will not pose

unnecessary risks to the electric distribution systems in the Commonwealth.29

25

See 52 Pa. Code §§ 75.61—75.70. 26

Net metering measures the difference between the electricity supplied by an electric utility or EGS and the electricity

generated by a customer-generator when any portion of the electricity generated by the alternative energy generating

system is used to offset part or all of the customer-generator’s requirements for electricity. See 52 Pa. Code § 75.12. 27

See Docket No. L-00050174; 52 Pa. Code §§ 75.11-75.15. 28

Id. 29

See Docket No. L-00050175; 52 Pa. Code §§ 75.21-75.40.


As of May 31, 2015, Pennsylvania had certified 10,78730

alternate energy facilities, of which 7,923

are located within the state. The statewide cost for AEPS compliance for all load-serving entities

in Pennsylvania is estimated to be $149.2 million for the year 2021.31

For additional information on Alternative Energy in Pennsylvania, please visit the Commission’s

website (http://www.puc.pa.gov/consumer_info/electricity/alternative_energy.aspx).

Energy Efficiency and Conservation (Act 129)

Act 129 of 2008

32 required the seven Pennsylvania EDCs

33 with at least 100,000 customers

34 to

establish an energy efficiency and conservation (EE&C) plan. The Commission-approved plans

were to reduce energy demand and consumption by 1 percent by May 31, 2011, and 3 percent by

May 31, 2013. Peak demand was to be reduced by 4.5 percent by May 31, 2013. Based on

forecast growth data, consumption reduction goals totaled 1,467 GWh in 2011 and 4,400 GWh in

2013. Peak demand reduction goals were projected to total 1,193 MW for 2013.35

The

Commission determined that, with the exception of West Penn Power, the EDCs achieved the 1

percent energy consumption reduction target by May 31, 2011. The Commission also determined

that all seven EDCs achieved both the 3 percent by May 31, 2013 consumption reduction and the

4.5 percent by May 31, 2013 peak demand reduction targets.36

Under Act 129, the Commission was also required to evaluate the costs and benefits of the EE&C

programs by Nov. 31, 2013, and every five years thereafter.37

The Commission determined the

benefits of consumption reduction requirements outweighed the costs. Based on the Act 129

Statewide Evaluator’s (SWE)38

Electric Energy Efficiency Potential for Pennsylvania Final

Report,39

the Commission set new consumption reduction targets to be attained in the three-year

period from Jun. 1, 2013, to May 31, 2016, (Phase II) for the EDCs subject to the Act 129 EE&C

requirements.40

These targets are outlined in Table 2, below.

30

See http://paaeps.com/credit/showStatistics.do 31

See http://www.puc.state.pa.us/electric/pdf/AEPS/AEPS_Ann_Rpt_2013.pdf 32

Act 129 of 2008, effective November 14, 2008; 66 Pa. C.S. §§2806.1-2806.2. 33

The seven EDCs with Act 129 Energy Efficiency and Conservation obligations are Duquesne Light Company;

Metropolitan Edison Company; PECO Energy Company; Pennsylvania Electric Company; Pennsylvania Power

Company; PPL Electric Utilities Corporation and West Penn Power Company. 34

See 66 Pa.C.S. § 2806.1. 35

See Energy Consumption and Peak Demand Reduction Targets Order, Docket No. M-2008-2069887, entered Mar.

30, 2009. 36

See Energy Efficiency and Conservation Program Order, Docket No. M-2008-2069887, entered Mar. 20, 2014. 37

See 66 Pa.C.S. §§ 2806.1(c) and (d) 38

Public Meeting of Jun. 25, 2009, the Commission selected GDS Associates, Inc. Engineers and Consultants as the

statewide evaluator for Phase I. 39

See the Electric Energy Efficiency Potential for Pennsylvania Final Report, available at

http://www.puc.pa.gov/filing_resources/issues_laws_regulations/act_129_information/act_129_statewide_evaluator_

swe_.aspx. 40

See Energy Efficiency and Conservation Program Implementation Order, Docket No. M-2012-2289411, entered

Aug. 3, 2012.

http://www.puc.pa.gov/consumer_info/electricity/alternative_energy.aspx

http://paaeps.com/credit/showStatistics.do

http://www.puc.state.pa.us/electric/pdf/AEPS/AEPS_Ann_Rpt_2013.pdf

http://www.puc.pa.gov/filing_resources/issues_laws_regulations/act_129_information/act_129_statewide_evaluator_swe_.aspx

http://www.puc.pa.gov/filing_resources/issues_laws_regulations/act_129_information/act_129_statewide_evaluator_swe_.aspx


Table 2 Phase II Consumption Reduction Targets

Act 129 Phase II Three-Year Consumption Reduction Targets

EDC

Three-Year % of

2009/10

Forecast Reductions

(%)

Three-Year MWh Value of 2009/10

Forecast Reductions

Duquesne 2.0 276,722

Met-Ed 2.3 337,753

PECO 2.9 1,125,851

Penelec 2.2 318,813

Penn Power 2.0 95,502

PPL 2.1 821,072

West Penn 1.6 337,533

While the Commission determined that energy efficiency programs were cost-effective, it did not

have enough information regarding the cost-effectiveness of Act 129 demand response programs in

order to set additional peak demand reduction targets for Phase II of Act 129.41 However,

assuming an EDC would be able to meet its Phase II consumption reduction target under its Act

129 budget, the Commission provided the opportunity for EDCs to propose, either in the EE&C

plans or otherwise, voluntary residential demand response programs.42 Additionally, the

Commission directed the SWE to perform a Demand Response Potential Study using residential

direct load control and commercial and industrial load curtailment models provided by the

Commission.43 This study was to provide the Commission with the information necessary to

determine whether Act 129 Phase III peak demand reduction programs would be cost-effective.

The SWE submitted its final version of the DR Potential Study to the Commission on February 25,

2015.44 The SWE also performed an Energy Efficiency (EE) Potential Study to determine the cost-

effective consumption reduction potential in Pennsylvania.45 The SWE submitted its final Energy

Efficiency Potential Study to the Commission on Feb. 25, 2015.46

Following a review of the SWE’s EE and DR Potential Studies, the Commission found that

additional consumption and peak demand reduction targets were cost-effective.47 On June 11,

2015, the Commission adopted a Final Implementation Order prescribing targets for a Phase III of

41

Id. at 38-42. 42

Id. at 42 and 43. 43

See Energy Efficiency and Conservation Program Final Order, Docket No. M-2012-2289411, entered Feb. 20, 2014. 44

See Demand Response Potential for Pennsylvania – Final Report, submitted by GDS Associates, Inc., et

al., February 25, 2015 (hereinafter DR Potential Study). 45

See Proposal to Pennsylvania Public Utility Commission – Statewide Evaluator RFP, submitted by GDS

Associates, Inc., et. al., January 11, 2013. 46

See Energy Efficiency Potential for Pennsylvania – Final Report, submitted by GDS Associates, Inc., et.

al., February 2015 (hereinafter EE Potential Study). 47

See Energy Efficiency and Conservation Program Final Implementation Order, Docket No. M-2014-2424864,

entered June 19, 2015, at 10-12.


the Act 129 EE&C Program, to operate June 1, 2016 through May 31, 2021.48 The EDCs’

consumption49 and peak demand reduction50 requirements are provided, below, in Tables 3 and 4,

respectively. While the EDCs must implement energy efficiency programs all five years of the

Phase III, the Commission required demand response programs only during the last four years of

the Phase, recognizing the time necessary to develop and implement such programs.51

Additionally, using the design and budgetary allocation information provided by the Commission,

the SWE found no cost-effective demand response potential in the Penelec service territory and,

therefore, the Commission did not prescribe a peak demand reduction requirement for Penelec.

Table 3 Phase III Consumption Reduction Targets

Act 129 Phase III Five-Year Consumption Reduction Targets

EDC

Five-Year % of

2009/10

Forecast Reductions

(%)

Five-Year MWh Value of 2009/10 Forecast

Reductions

Duquesne 3.1 440,916

Met-Ed 4.0 599,352

PECO 5.0 1,962,659

Penelec 3.9 566,168

Penn Power 3.3 157,371

PPL 3.8 1,443,035

West Penn 2.6 540,986

Table 4 Phase III Peak Demand Reduction Targets

Act 129 Phase III Four-Year Peak Demand Reduction Targets

EDC

Four-Year %

Reduction (Relative to

2007-2008 Peak

Demand)

Average Annual Potential Savings (MW)

Duquesne 1.7 42

Met-Ed 1.8 49

PECO 2.0 161

Penelec 0.0 0

Penn Power 1.7 17

PPL 1.4 92

West Penn 1.8 64

48

Id. at 14-15. 49

Id. at 57. 50

Id. at 35. 51

Id. at 35.


Statewide Review of Electrical Energy Usage

Pennsylvania’s aggregate electrical energy usage (residential, commercial, industrial, sales for

resale, and other) in 2014 was 146,516 GWh versus 146,235 GWh for 2013, which is a 0.2 percent

increase in electrical usage. The number of electrical energy customers increased by 16,836 or

0.39 percent. Residential usage represented 35.2 percent of the total usage, followed by industrial

(32.5 percent), and commercial (28.6 percent). Aggregate non-coincident peak load52

decreased to

29,952 MW in 2014 from 30,021 MW in 2013, which is a 0.2 percent decrease from the previous

year.

The total average aggregate five-year energy usage growth projection for the residential,

commercial and industrial classes is 0.44 percent per year as shown in Table 5. This includes an

average residential growth rate decrease of 0.01 percent, a commercial growth rate decrease of

0.03 percent, and an industrial growth rate increase of 1.32 percent for the entire five-year period.

Only the industrial class growth rate was higher than the comparable PJM 10-year forecast of 1.0

percent annual growth rate for the mid-Atlantic region.53

Table 5 Average Aggregate five-year Electrical Energy Projection

Individual EDC forecasts are more specific to customers and geographical areas. Each EDC bases

its forecasts on financial forecasts of its choosing. The EDC’s forecasts are more specific for its

territory than the PJM forecasts, which is a broader forecast that includes Pennsylvania EDC

territories. Tables 6 and 7 below provide metrics for 2014 and 2013, respectively.

52

Non-coincident peak load is the sum of EDCs’ annual peak loads regardless of their date or time of occurrence. 53

See PJM load forecast report 2015, Table E-1, available at http://www.pjm.com/~/media/documents/reports/2015-

load-forecast-report.ashx

Year Residential Commercial Industrial Total

2015 50,812 41,888 47,346 140,046

2016 50,417 41,602 48,230 140,249

2017 50,613 41,810 48,941 141,364

2018 50,773 41,872 49,524 142,169

2019 50,799 41,831 49,903 142,533

average annual growth (%) -0.01 -0.03 1.32 0.44

Energy Usage Projection (GWh)


Table 6 PA EDC customers served, energy usage, and peak load (2014)

Table 7 PA EDC customers served, energy usage, and peak load (2013)

Figure 3 shows Pennsylvania historic and forecast energy usage for residential, commercial and

industrial retail from 1972 to 2014 and forecasted usage from 2015 to 2019.

Total Sales For Total System Company Net Energy Peak

Customers Resale Consumption Losses Use For Load Load

Served (MWh) (MWh) (MWh) (MWh) (MWh) (MWh) (MWh) (MWh) (MWh) (MW)

Duquesne 591,750 4,068,016 6,431,805 3,164,231 58,452 24,835 13,747,339 667,123 36,528 13,043,688 2,693

Met-Ed 557,803 5,477,233 2,944,043 5,382,193 28,858 539,278 14,371,606 1,097,404 0 13,274,202 2,817

Penelec 588,274 4,461,845 3,591,256 5,646,861 38,641 2,548,112 16,286,715 1,584,888 0 14,701,827 3,024

Penn Power 162,577 1,728,349 1,381,442 1,598,555 6,142 221,039 4,935,527 241,333 0 4,694,194 1,018

PPL 1,416,655 14,562,909 14,111,306 8,312,629 157,433 0 37,144,277 2,679,357 69,018 34,395,902 7,816

PECO 1,594,763 13,222,177 8,025,119 15,309,577 937,404 180,462 37,674,739 2,265,504 6,746 35,402,489 8,258

West Penn 721,158 7,281,289 4,955,687 7,972,140 48,081 754,700 21,011,897 1,473,035 0 19,538,862 4,019

UGI 62,003 543,149 316,181 110,622 5,688 131 975,771 92,165 1,988 881,618 211

Citizens' 6,889 88,335 29,440 53,974 600 0 172,349 4,287 195 167,867 52

Pike County 4,673 30,433 44,583 0 395 0 75,411 0 116 75,295 19

Wellsboro 6,248 44,002 32,482 43,595 220 97 120,396 13,216 220 106,960 26

Total 5,712,793 51,507,737 41,863,344 47,594,377 1,281,914 4,268,654 146,516,027 10,118,312 114,811 136,282,904 29,952

% of Total 35.16% 28.57% 32.48% 0.87% 2.91% 100.00%

CompanyResidential Commercial Industrial Other

Total Sales For Total System Company Net Energy Peak

Customers Resale Consumption Losses Use For Load Load

Served (MWh) (MWh) (MWh) (MWh) (MWh) (MWh) (MWh) (MWh) (MWh) (MW)

Duquesne 591,815 4,090,906 6,494,254 3,337,255 60,635 24,223 14,007,272 677,542 29,249 13,300,481 2,951

Met-Ed 555,729 5,553,153 2,933,482 5,328,311 28,868 544,502 14,388,316 1,082,202 0 13,306,114 3,012

Penelec 589,755 4,490,880 3,531,240 5,731,434 38,627 2,431,531 16,223,713 1,570,453 0 14,653,260 3,087

Penn Power 161,870 1,703,976 1,348,582 1,508,839 6,212 192,213 4,759,822 345,978 0 4,413,844 962

PPL 1,410,345 14,295,182 14,140,450 8,051,581 203,532 0 36,690,745 2,646,353 64,151 33,980,241 7,190

PECO 1,586,969 13,340,802 8,100,575 15,378,728 936,139 287,886 38,044,130 2,332,503 38,491 35,673,136 8,618

West Penn 719,572 7,318,190 4,878,138 7,776,666 47,663 737,202 20,757,860 1,430,142 0 19,327,718 3,914

UGI 62,089 558,418 327,355 109,174 5,627 128 1,000,701 73,086 1,983 925,632 205

Citizens' 6,883 85,565 29,024 53,195 616 0 168,400 9,021 190 159,189 37

Pike County 4,673 30,364 43,597 0 414 0 74,375 122 74,253 19

Wellsboro 6,257 43,840 32,391 42,651 221 112 119,215 9,982 283 108,950 26

Total 5,695,957 51,511,276 41,859,088 47,317,834 1,328,554 4,217,797 146,234,549 10,177,262 134,469 135,922,818 30,021

% of Total 35.23% 28.62% 32.36% 0.91% 2.88% 100.00%

OtherCompany

Residential Commercial Industrial


Figure 3 Pennsylvania retail energy usage and 5 year forecast (GWh)

Figure 4 shows average residential cost and average usage from 1940 to 2014. Between 1970 and

2010, average residential usage in Pennsylvania increased 1.4 percent each year, while average

cost increased 4.1 percent each year. During the last 10 years, average residential usage increased

0.73 percent each year, while average cost increased 1.6 percent a year.

Figure 4 Average residential cost (cents/kWh) and usage (MWh/year)

10,000

14,000

18,000

22,000

26,000

30,000

34,000

38,000

42,000

46,000

50,000

54,000

58,000

Gig

aw

att

ho

urs

Residential Commercial Industrial

0

1

2

3

4

5

6

7

8

9

10

11

12

13

Cost per kWh

MWh per year

Utility Restructuring


Figure 5 shows Pennsylvania’s aggregate non-coincidental peak load demand from 2005 to 2014

and the associated 5 year projections estimated during the last 3 years.

Figure 5 Pennsylvania aggregate non-coincidental peak load (MW)

26,000

26,500

27,000

27,500

28,000

28,500

29,000

29,500

30,000

30,500

31,000

31,500

32,000

2005 2006 2007 2008 2009 2010 2011 2012 2013 2014 2015 2016 2017 2018 2019

Historic ______ Forecasts _ _ _ _

2013

2014

2015


Summary of Data for the Seven Largest EDCs

The following sections provide historic and projected energy usage and peak load demand

statistics, purchases from cogeneration and small power production projects, planned transmission

line additions, and conservation activities for Pennsylvania’s seven largest EDCs.

Duquesne Light Company (Duquesne)

Duquesne provides electric service to 591,750

customers in the City of Pittsburgh and portions of

Allegheny and Beaver counties in Southwestern

Pennsylvania. Duquesne’s 2014 energy usage total

was 13,722 GWh, while in 2013 it was 14,007 GWh

(a decrease of 2.0 percent from the previous year).

Duquesne’s total usage mix consisted of commercial

(47 percent), residential (30 percent), industrial (23

percent), and sales for resale (less than 1 percent).

Over the next five years, total energy usage is projected to decrease at an average annual rate of 0.4

percent. This includes an average annual increase in residential usage of 0.5 percent, commercial

usage is projected to stay the same, and a decrease in average annual of industrial usage by 2.1

percent. See Figure 6.

Duquesne’s highest peak load of 2,693 MW occurred on July 1, 2014. This represents a decrease

of 9 percent from the previous year’s peak of 2,951 MW. Summer peak load is projected to

increase from 2,693 MW in summer 2014 to 3,056 MW by summer 2019, or by an average annual

growth rate increase of 2.6 percent. See Figure 7.

Refer to Appendix A, Tables A01-A04 for Duquesne’s forecasts of peak load and residential,

commercial and industrial energy demand, filed with the Commission in years 2005 through 2015.


Figure 6 Duquesne energy usage (GWh)

Figure 7 Duquesne peak load (MW)

2000

2500

3000

3500

4000

4500

5000

5500

6000

6500

7000

7500

2005 2006 2007 2008 2009 2010 2011 2012 2013 2014 2015 2016 2017 2018 2019

Commercial

Residential

Industrial

Historic Forecasts

2,500

2,600

2,700

2,800

2,900

3,000

3,100

3,200

3,300

2005 2006 2007 2008 2009 2010 2011 2012 2013 2014 2015 2016 2017 2018 2019

Historic Forecasts _ _ _ _ _

20152013 2014


Metropolitan Edison Company (Met-Ed)

Met-Ed provides service to 557,803 customers in

all or portions of 14 counties in Eastern and

Southcentral Pennsylvania. Met-Ed’s 2014 energy

usage total was 14,372 GWh, while in 2013 it was

14,388 GWh (a decrease of 0.1 percent from the

previous year). Met-Ed’s total sales mix consisted

of residential (38 percent), industrial (37 percent),

commercial (20 percent), and sales for resale (3.7

percent).

Over the next five years, total energy usage is projected to remain flat. This includes a decrease in

average annual residential usage of 0.5 percent, a decrease in average annual commercial usage by

0.1 percent, and an increase in average annual industrial usage by 0.6 percent. See Figure 8.

Met-Ed’s highest peak load of 2,817 MW occurred on July 23, 2014. This represents a decrease of

6.5 percent from previous year’s peak of 3,012 MW. Summer peak load is projected to increase

from 2,817 MW in summer 2014 to 2,986 MW by summer 2019, or by an average annual growth

rate increase of 1.2 percent. See Figure 9.

Refer to Appendix A, Tables A05-A08 for Met-Ed’s forecasts of peak load and residential,



Figure 8 Met-Ed energy usage (GWh)

Figure 9 Met-Ed peak load (MW)

2,000

2,200

2,400

2,600

2,800

3,000

3,200

3,400

3,600

3,800

4,000

4,200

4,400

4,600

4,800

5,000

5,200

5,400

5,600

5,800

6,000

2005 2006 2007 2008 2009 2010 2011 2012 2013 2014 2015 2016 2017 2018 2019

Residential

Commercial

IndustrialHistoric Forecasts

2,200

2,300

2,400

2,500

2,600

2,700

2,800

2,900

3,000

3,100

3,200

3,300

2005 2006 2007 2008 2009 2010 2011 2012 2013 2014 2015 2016 2017 2018 2019

20152014

2013

Historic ______ Forecasts _ _ _ _ _


Pennsylvania Electric Company (Penelec)

Penelec provides service to 588,274 customers in

all or portions of 29 counties in Western and

Northern Pennsylvania. Penelec’s 2014 energy

usage total was 16,287 GWh, while in 2013 it

was 16,224 GWh (an increase of 0.4 percent

from the previous year). Penelec’s total sales

mix consisted of residential (27 percent),

commercial (22 percent), industrial (35 percent),

and sales for resale (0.2 percent).

Over the next five years, total energy usage is projected to increase at an average annual rate of 0.4

percent. This includes a decrease in average annual in residential usage of 0.4 percent, an increase

in average annual in commercial usage by 0.1 percent, and an increase in average annual industrial

usage by 1.2 percent. See Figure 10.

Penelec’s highest peak load of 3,024 MW occurred on Feb. 19, 2015. This represents a decrease of

2 percent from previous year’s peak of 3,087 MW. Winter peak load is projected to decrease from

3,024 MW in winter 2015 to 2,902 MW by winter 2019, or by an average annual growth rate

decrease of 0.8 percent. See Figure 11.

Refer to Appendix A, Tables A09-A12 for Penelec’s forecasts of peak load and residential,



Figure 10 Penelec energy usage (GWh)

Figure 11 Penelec peak load (MW)

3000

3500

4000

4500

5000

5500

6000

6500

7000

2005 2006 2007 2008 2009 2010 2011 2012 2013 2014 2015 2016 2017 2018 2019

Historic Forecasts

Commercial

Residential

Industrial

2,000

2,200

2,400

2,600

2,800

3,000

3,200

3,400

3,600

3,800

4,000

2005 2006 2007 2008 2009 2010 2011 2012 2013 2014 2015 2016 2017 2018 2019


20132014 2015


Pennsylvania Power Company (Penn Power)

Penn Power provides service to 162,577 customers in

all or portions of six counties in Western

Pennsylvania. Penn Power’s 2014 energy usage total

was 4,936 GWh, while in 2013 it was 4,760 GWh (an

increase of 3.7 percent from the previous year). Penn

Power’s total usage mix consisted of residential (35

percent), commercial (28 percent), industrial (32

percent), and sales for resale (4 percent).


percent. This includes a decrease in average annual in residential usage of 0.2 percent, a decrease

in average annual commercial usage of 5 percent, and an increase in average annual industrial

usage of 6.0 percent. See Figure 12.

Penn Power's highest peak load of 1,018 MW occurred on Feb. 23, 2015. This represents a

decrease 3.4 percent from the previous year’s peak of 1,054 MW. Winter peak load is projected to

decrease from 1,018 MW in winter 2015 to 949 MW by winter 2019, or by an average annual

growth rate decrease of 1.4 percent. See Figure 13.

Refer to Appendix A, Tables A13-A16 for Penn Power’s forecasts of peak load and residential,



Figure 12 Penn Power energy usage (GWh)

Figure 13 Penn Power peak load (MW)

900

1,000

1,100

1,200

1,300

1,400

1,500

1,600

1,700

1,800

1,900

2,000

2,100

2,200

2,300

2,400

2005 2006 2007 2008 2009 2010 2011 2012 2013 2014 2015 2016 2017 2018 2019

Historic Forecasts

Residential

Commercial

Industrial

800

850

900

950

1,000

1,050

1,100

1,150

1,200

2005 2006 2007 2008 2009 2010 2011 2012 2013 2014 2015 2016 2017 2018 2019


2013

2014

2015


West Penn Power Company (West Penn)

West Penn provides service to 721,158 customers in

all or portions of 24 counties in Western, North and

South Central Pennsylvania. West Penn’s 2014

energy usage total was 21,012 GWh, while in 2013 it

was 20,758 GWh (an increase of 1.2 percent from the

previous year). West Penn’s total usage mix consisted

of residential (35 percent), commercial (24 percent),

industrial (38 percent), and sales for resale (less than 4

percent).


percent. This includes an increase in average annual residential usage of 0.1 percent, an increase in

average annual commercial usage of 0.2 percent, and an increase in average annual industrial usage

of 4.3 percent. See Figure 14.

West Penn’s highest peak load of 4,019 MW occurred on Feb. 19, 2015. This represents a

decrease of 1.4 percent from the previous year’s peak of 4,075 MW. Summer peak load is

projected to increase from 4,019 MW in 2014 to 4,031 MW by the year 2019, or by an average

annual growth rate increase of .01 percent. See Figure 15.

Refer to Appendix A, Tables A25-A28 for West Penn’s forecasts of peak load and residential,



Figure 14 West Penn energy usage (GWh)

Figure 15 West Penn peak load (MW)

4,000

4,500

5,000

5,500

6,000

6,500

7,000

7,500

8,000

8,500

9,000

9,500

10,000

2005 2006 2007 2008 2009 2010 2011 2012 2013 2014 2015 2016 2017 2018 2019

Historic Forecasts

Industrial

Residential

Commercial

3,200

3,300

3,400

3,500

3,600

3,700

3,800

3,900

4,000

4,100

4,200

4,300

2005 2006 2007 2008 2009 2010 2011 2012 2013 2014 2015 2016 2017 2018 2019


2013

2014

2015


PECO Energy Company (PECO)

PECO is the largest electric utility in Pennsylvania,

providing service to 1,594,763 customers in the City

of Philadelphia and all or portions of six counties in

Southeastern Pennsylvania. PECO’s 2014 energy

usage total was 37,675 GWh, while in 2013 it was

38,044 GWh (a decrease of 1.0 percent from the

previous year). PECO’s total usage mix consisted of

residential (35 percent), commercial (21 percent),

industrial (40 percent), other54

(2.5 percent), and sales

for resale (0.5 percent).


percent. This includes an increase in average annual residential usage of 0.5 percent, flat

commercial growth, and a decrease in average annual industrial usage by 0.1 percent. See Figure

16.

PECO’s highest peak load of 8,258 MW occurred on July 2, 2014. This represents a decrease of 4

percent from the previous year’s peak of 8,618 MW. Summer peak load is projected to increase

from 8,258 MW in summer 2014 to 8,292 MW by summer 2019, or by an average annual growth

rate increase of 0.1 percent. See Figure 17.

Refer to Appendix A, Tables A21-A24 for PECO’s forecasts of peak load and residential,


54

Sales in the “other” category include public streetlights, highway lighting, other public authorities, railroads,

railways, and interdepartmental.


Figure 16 PECO energy usage (GWh)

Figure 17 PECO Energy Company peak load (MW)

6,000

7,000

8,000

9,000

10,000

11,000

12,000

13,000

14,000

15,000

16,000

17,000

18,000

2005 2006 2007 2008 2009 2010 2011 2012 2013 2014 2015 2016 2017 2018 2019

Historic Forecasts

Residential

Industrial

Commercial

7,100

7,300

7,500

7,700

7,900

8,100

8,300

8,500

8,700

8,900

9,100

9,300

9,500

9,700

2005 2006 2007 2008 2009 2010 2011 2012 2013 2014 2015 2016 2017 2018 2019


20132014

2015


PPL Electric Utilities Corporation (PPL)

PPL provides service to 1,416,655 customers over

a 10,000-square-mile area in all or portions of 29

counties in Central Eastern Pennsylvania. PPL’s

2014 energy usage total was 37,144 GWh, while

in 2013 it was 36,691 GWh (an increase of 1.2

percent from the previous year). PPL’s total usage

mix consisted of residential (37 percent),


and other (0.4 percent).

Over the next five years, total energy usage is projected to decrease at an average annual rate of 0.3

percent. This includes a decrease in average annual residential usage of 1.1 percent, an increase in

average annual commercial usage of 0.5 percent, and a decrease in average annual industrial usage

of 0.3 percent. See Figure 18.

PPL’s highest peak load of 7,816 MW occurred on Jan. 7, 2014. This represents an increase of 8.7

percent from the previous year’s peak of 7,190 MW. Winter peak load is projected to decrease

from 7,816 MW in 2014 to 7,511 MW by the year 2019, or by an average annual growth rate

decrease of 0.8 percent. See Figure 19.

Refer to Appendix A, Tables A17-A20 for PPL’s forecasts of peak load and residential,



Figure 18 PPL Electric Utilities Corporation energy usage (GWh)

Figure 19 PPL Electric Utilities Corporation peak load (MW)

7,000

8,000

9,000

10,000

11,000

12,000

13,000

14,000

15,000

16,000

2005 2006 2007 2008 2009 2010 2011 2012 2013 2014 2015 2016 2017 2018 2019

Historic Forecast

Residential

Commercial

Industrial

6,500

6,700

6,900

7,100

7,300

7,500

7,700

7,900

8,100

2005 2006 2007 2008 2009 2010 2011 2012 2013 2014 2015 2016 2017 2018 2019


2014

2013

2015


Summary of Data for the Four Smallest EDCs Citizens’ Electric Company (Citizens’)

Citizens’ provides service to 6,889 customers in

Union County, Pennsylvania. Citizens’ 2014 energy

usage total was 172 GWh, while in 2013 it was 168

GWh (an increase of 2.3 percent from previous

year). Citizens’ total usage mix consisted of

residential (51 percent), commercial (17 percent),

industrial (31 percent), and other (< 1 percent).


percent. This includes a decrease in average annual residential usage of 1.3 percent, an increase in

average annual commercial usage of 2.0 percent, and a decrease in average annual industrial usage

of 0.5 percent. See Figure 20 below.

Citizens’ highest peak load of 51.9 MW occurred on Feb. 20, 2015. This represents an increase of

3.5 percent from the previous year’s peak of 50.1 MW. Winter peak load is projected to grow

from 51.9 MW in 2014 to 54.4 MW by the year 2019, or by an average annual growth rate increase

of .5 percent.

Figure 20 Citizens' energy usage (GWh)

0.00

10.00

20.00

30.00

40.00

50.00

60.00

70.00

80.00

90.00

100.00

110.00

120.00

2005 2006 2007 2008 2009 2010 2011 2012 2013 2014 2015 2016 2017 2018 2019


Residential

Industrial

Commercial


Pike County Light & Power Company (Pike)

Pike provides service to 4,673 customers in

Eastern Pike County, Northeastern

Pennsylvania. Pike’s 2014 energy usage total

was 75.0 GWh, which was the same as in

2013. Pike’s total usage mix consisted of

residential (40 percent) and commercial (59

percent). Pike has no industrial customers or

sales for resale.


percent, which includes an increase in average annual residential growth rate of 0.9 percent and an

increase in average annual commercial growth rate of 0.9 percent. See Figure 21.

Pike’s highest peak load of 19 MW occurred on July 2, 2014. This represents an increase of 2.7

percent from the previous year’s peak of 18.5 MW. Summer peak load is projected to remain the

same from 19 MW in summer 2014 to 19 MW by summer 2019, with zero average annual growth.

Figure 21 Pike County Light & Power energy usage (GWh)

20

25

30

35

40

45

50

55

2005 2006 2007 2008 2009 2010 2011 2012 2013 2014 2015 2016 2017 2018 2019


Residential

Commercial


UGI Utilities Inc.—Electric Division (UGI)

UGI provides electric service to 62,003

customers in Northwestern Luzerne and

Southern Wyoming counties in Pennsylvania.

UGI’s 2014 energy usage total was 976 GWh,

while in 2013 it was 1001 GWh (a decrease of

2.5 percent from the previous year). UGI’s total

usage mix consisted of residential (56 percent),


and sales for resale (0.01 percent).


percent, which includes a flat average annual residential growth, an increase in average annual

commercial growth rate of 1.2, and decrease in industrial annual growth rate of 0.4 percent. See

Figure 22.

UGI’s highest peak load of 211 MW occurred on Feb. 20, 2015. This represents an increase of 3

percent from the previous year’s peak of 205 MW. Winter peak load is projected to decrease from

211 MW in winter 2015 to 207 MW by the year 2019, or by an average annual growth rate

decrease of 0.4 percent.

Figure 22 UGI Utilities Inc. energy usage (GWh)

50

100

150

200

250

300

350

400

450

500

550

600

650

2005 2006 2007 2008 2009 2010 2011 2012 2013 2014 2015 2016 2017 2018 2019

Historic Forecasts

Residential

Commercial

Industrial


Wellsboro Electric Company (Wellsboro)

Wellsboro provides electric service to 6,248

customers in Tioga County, North Central

Pennsylvania. Wellsboro’s 2014 energy usage

total was 120.4 GWh, while in 2013 it was

119.2 GWh (an increase of 1.0 percent from the

previous year). Wellsboro’s total usage mix

consisted of residential (37 percent),

commercial (27 percent), and industrial (36

percent.

Over the next five years, total energy usage is projected to grow at an average annual rate of 0.7

percent. This includes an increase in average annual residential growth rate of 0.8 percent, an

increase in average annual commercial growth rate of 1.2 percent, and an increase in average

annual industrial growth rate of 0.2 percent. See Figure 23.

Wellsboro’s highest peak load of 26 MW occurred on Dec. 12, 2015. This represents an increase

of 13 percent from the previous year’s peak of 23 MW. Winter peak load is projected to grow

from 26 MW in 2014 to 27 MW by the year 2019, or by an average annual growth rate of 0.76

percent.

Figure 23 Wellsboro Electric Company energy usage (GWh)

20.00

25.00

30.00

35.00

40.00

45.00

50.00

55.00

60.00

2005 2006 2007 2008 2009 2010 2011 2012 2013 2014 2015 2016 2017 2018 2019


Residential

Industrial

Commercial


Appendix A – Data Tables

The following tables provide actual and projected peak load as well as residential, commercial and

industrial energy demand by EDC. Actual data covers years 2005 through 2014. Five-year

projections are those filed with the Commission in years 2005 through 2015.


Table A01 Duquesne Light Company Table A03 Duquesne Light CompanyActual and Projected Peak Load (MW) Actual and Projected Commercial Energy Demand (GWh)

Projected Peak Load Requirments Projected Commercial Energy Demand(Year Forecast Was Filed) (Year Forecast Was Filed)

Year Actual 2005 2006 2007 2008 2009 2010 2011 2012 2013 2014 2015 Year Actual 2005 2006 2007 2008 2009 2010 2011 2012 2013 2014 2015

2005 2884 2722 2005 6566 6568

2006 3053 2765 2765 2006 6474 6711 6693

2007 2890 2805 2805 3039 2007 6715 6870 6847 6784

2008 2822 2835 2835 3086 2948 2008 6631 6949 6991 6942 6731

2009 2732 2873 2873 3141 3007 2862 2009 6537 7076 7129 7127 6768 6648

2010 2889 2910 3194 3067 2836 2854 2010 6712 7259 7302 6815 6627 6428

2011 3012 3242 3128 2857 2863 2944 2011 6612 7457 6878 6583 6501 6681

2012 3054 3191 2850 2860 3000 2935 2012 6539 6952 6533 6585 6782 6682

2013 2951 2890 2917 3053 2980 2966 2013 6494 6527 6666 6854 6749 6642

2014 2693 2960 3088 3045 3021 2997 2014 6432 6742 6957 6842 6640 6600

2015 3125 3102 3083 3056 2969 2015 7056 6929 6640 6621 6494

2016 3132 3135 3094 3005 2016 7017 6645 6648 6503

2017 3167 3118 3026 2017 6641 6643 6472

2018 3143 3042 2018 6654 6455

2019 3056 2019 6430

Table A02 Duquesne Light Company Table A04 Duquesne Light CompanyActual and Projected Residential Energy Demand (GWh) Actual and Projected Industrial Energy Demand (GWh)

Projected Residential Energy Demand Projected Industrial Energy Demand(Year Forecast Was Filed) (Year Forecast Was Filed)


2005 4134 3941 2005 3128 3347

2006 3991 4018 3984 2006 3182 3407 3229

2007 4211 4088 4054 4141 2007 3145 3458 3299 3271

2008 4060 4125 4118 4214 4216 2008 3079 3501 3359 3315 3098

2009 3946 4198 4181 4293 4293 4177 2009 2616 3542 3411 3369 3102 3002

2010 4327 4243 4372 4371 4188 4117 2010 2987 3464 3420 3084 2933 2440

2011 4232 4453 4444 4181 4184 4213 2011 3120 3467 3140 2851 2407 2865

2012 4169 4527 4171 4267 4275 4350 2012 3406 3141 2777 2395 2846 3185

2013 4091 4197 4352 4332 4436 4246 2013 3337 2726 2385 2815 3226 3501

2014 4068 4448 4402 4509 4260 4217 2014 3164 2359 2770 3252 3035 2787

2015 4474 4579 4265 4230 4176 2015 2724 3272 3032 2778 2909

2016 4676 4284 4266 4202 2016 3289 3031 2762 2896

2017 4306 4266 4184 2017 3031 2734 2873

2018 4272 4172 2018 2711 2851

2019 4164 2019 2826


Table A05 Metropolitan Edison Company Table A07 Metropolitan Edison CompanyActual and Projected Peak Load (MW) Actual and Projected Commercial Energy Demand (GWh)* Energy Sales (GWH)

Projected Peak Load Requirements Projected Commercial Energy Demand(Year Forecast Was Filed) (Year Forecast Was Filed)


2005 2752 2625 2005 4491 4310

2006 2884 2689 2689 2006 4509 4400 4462

2007 2825 2740 2740 2740 2007 4715 4506 4547 4664

2008 3045 2801 2801 2801 2801 2008 4777 4616 4668 4818 4818

2009 2739 2857 2856 2857 2857 2829 2009 4568 4721 4788 4969 4969 4853

2010 2715 2915 2915 2915 2932 2687 2010 3006 4908 5108 5108 5020 4671

2011 3125 2972 2972 3017 2640 2869 2011 2947 5244 5244 5152 4706 2955

2012 3036 3032 3085 2630 2775 2911 2012 2907 5375 5291 4783 2959 2871

2013 3012 3158 2668 2815 2928 2881 2013 2933 5421 4887 3019 2909 2900

2014 2817 2731 2872 2962 2887 2958 2014 2944 4963 3090 2948 2930 2914

2015 2952 2995 2898 2965 2975 2015 3158 2997 2937 2931 2983

2016 3028 2910 2974 2979 2016 2995 2940 2964 2929

2017 2932 2996 2985 2017 2956 2984 2938

2018 3017 2987 2018 2989 2938

2019 2986 2019 2923

* The 2010 actual and 2011 forecast are based on a reclassification of the commercial and industrial classes.

Table A06 Metropolitan Edison Company Table A08 Metropolitan Edison CompanyActual and Projected Residential Energy Demand (GWh) Actual and Projected Industrial Energy Demand (GWh)*



2005 5399 5097 2005 4083 4077

2006 5287 5176 5325 2006 4008 4119 4176

2007 5595 5276 5390 5516 2007 3992 4145 4155 4123

2008 5598 5376 5515 5699 5699 2008 3831 4175 4177 4156 4156

2009 5448 5472 5640 5872 5872 5771 2009 3439 4195 4200 4181 4181 3620

2010 5666 5764 6037 6037 5836 5587 2010 5288 4221 4193 4193 3842 3538

2011 5588 6187 6187 5969 5552 5424 2011 5404 4201 4201 4035 3497 5443

2012 5363 6341 6109 5577 5226 5201 2012 5261 4209 4047 3528 5545 5434

2013 5553 6232 5682 5386 5184 5297 2013 5328 4048 3731 5589 5652 5411

2014 5477 5799 5547 5183 5159 5354 2014 5382 4021 5610 5765 5521 5322

2015 5650 5212 5042 5421 5533 2015 5625 5851 5561 5381 5413

2016 5210 4979 5438 5378 2016 5847 5587 5456 5472

2017 4993 5457 5392 2017 5612 5508 5507

2018 5476 5382 2018 5524 5523

2019 5351 2019 5532



Table A09 Pennsylvania Electric Company Table A11 Pennsylvania Electric CompanyActual and Projected Peak Load (MW) Actual and Projected Commercial Energy Demand (GWh)* Energy Sales



2005 2425 2438 2005 4792 4825

2006 2531 2481 2511 2006 5010 4912 4928

2007 2696 2525 2554 2554 2007 4961 4986 4990 5049

2008 2524 2565 2598 2598 2598 2008 5139 5060 5064 5099 5045

2009 2880 2604 2637 2637 2637 2637 2009 5186 5136 5140 5188 5122 5122

2010 2451 2674 2674 2674 2674 2603 2010 5019 5213 5277 5199 5199 5159

2011 2659 2711 2711 2711 2630 2465 2011 3671 5367 5277 5277 5213 5196

2012 3128 2750 2750 2661 2452 2515 2012 3534 5356 5356 5265 5215 3562

2013 3087 2789 2688 2458 2544 2938 2013 3531 5436 5320 5257 3526 3512

2014 3024 2715 2496 2579 2942 2927 2014 3591 5364 5343 3593 3535 3553

2015 2531 2625 2987 2935 2888 2015 5424 3650 3510 3552 3649

2016 2662 3039 2946 2896 2016 3698 3503 3582 3582

2017 3081 2962 2904 2017 3503 3604 3614

2018 2968 2904 2018 3608 3619

2019 2902 2019 3607


Table A10 Pennsylvania Electric Company Table A12 Pennsylvania Electric CompanyActual and Projected Residential Energy Demand (GWh) Actual and Projected Industrial Energy Demand (GWh)*



2005 4249 4135 2005 4589 4561

2006 4457 4186 4295 2006 4729 4666 4527

2007 4381 4236 4333 4420 2007 4678 4737 4612 4807

2008 4497 4287 4385 4438 4469 2008 4610 4791 4679 4828 4809

2009 4558 4339 4438 4496 4533 4533 2009 4594 4815 4708 4881 4881 4881

2010 4471 4524 4554 4598 4598 4611 2010 4044 4725 4905 4954 4954 4203

2011 4656 4614 4662 4662 4614 4569 2011 5748 4930 4983 4983 4538 4126

2012 4554 4727 4727 4662 4489 4460 2012 6005 5013 5013 4859 4222 6026

2013 4491 4793 4721 4443 4304 4257 2013 5731 5043 4889 4370 6175 5883

2014 4462 4776 4442 4387 4164 4469 2014 5647 4922 4607 6266 5993 5696

2015 4486 4539 4145 4513 4491 2015 4674 6304 6062 5808 5747

2016 4653 4157 4525 4373 2016 6325 6133 5867 5822

2017 4156 4554 4393 2017 6130 5894 5931

2018 4583 4394 2018 5896 6017

2019 4377 2019 5998



Table A13 Pennsylvania Power Company Table A15 Pennsylvania Power CompanyActual and Projected Peak Load (MW) Actual and Projected Commercial Energy Demand (GWh) Energy Sales



2005 1021 952 2005 1367 1353

2006 984 921 904 2006 1359 1374 1384

2007 1042 930 930 921 2007 1414 1400 1422 1394

2008 1063 938 938 936 936 2008 1404 1427 1460 1427 1427

2009 901 951 951 951 951 984 2009 1367 1453 1498 1461 1461 1401

2010 903 965 965 965 941 896 2010 1311 1535 1496 1496 1394 1428

2011 1102 980 980 963 890 944 2011 1327 1532 1532 1424 1408 1300

2012 963 994 981 899 947 1010 2012 1334 1569 1491 1449 1267 1291

2013 1054 995 930 983 1001 929 2013 1349 1535 1500 1272 1297 1337

2014 1018 977 1002 1003 930 867 2014 1381 1535 1277 1314 1347 1345

2015 1010 1006 953 873 931 2015 1278 1335 1358 1322 1180

2016 1010 969 880 940 2016 1334 1365 1326 1048

2017 980 885 947 2017 1374 1332 1049

2018 889 949 2018 1332 1047

2019 949 2019 1040

Table A14 Pennsylvania Power Company Table A16 Pennsylvania Power CompanyActual and Projected Residential Energy Demand (GWh) Actual and Projected Industrial Energy Demand (GWh)



2005 1664 1612 2005 1629 1582

2006 1611 1636 1659 2006 1708 1558 1565

2007 1690 1665 1699 1659 2007 1627 1563 1578 1720

2008 1667 1695 1744 1693 1693 2008 1614 1568 1594 1727 1727

2009 1634 1723 1789 1724 1724 1780 2009 1229 1569 1610 1734 1734 1347

2010 1696 1835 1758 1758 1761 1701 2010 1488 1626 1741 1741 1517 1226

2011 1711 1789 1789 1806 1708 1664 2011 1542 1748 1748 1687 1214 1527

2012 1668 1821 1860 1721 1624 1590 2012 1456 1755 1694 1238 1652 1513

2013 1704 1904 1714 1638 1588 1645 2013 1509 1700 1370 1705 1483 1473

2014 1728 1739 1664 1582 1627 1677 2014 1599 1596 1725 1486 1518 1596

2015 1684 1589 1619 1685 1752 2015 1738 1490 1519 1743 1847

2016 1588 1625 1691 1689 2016 1490 1488 1739 2079

2017 1649 1699 1703 2017 1485 1729 2202

2018 1705 1713 2018 1731 2256

2019 1714 2019 2278


Table A17 PPL Electric Utilities Corporation Table A19 PPL Electric Utilities CorporationActual and Projected Peak Load (MW) Actual and Projected Commercial Energy Demand (GWh) Energy Sales (GWH)



2005 7083 7200 2005 13157 12967

2006 7577 7290 7310 2006 13140 13436 13188

2007 7163 7390 7410 7200 2007 13756 13946 13562 13184

2008 7414 7490 7510 7270 7410 2008 13913 14517 13836 13476 13676

2009 6845 7580 7610 7340 7450 7180 2009 13818 15068 14166 13777 14028 14258

2010 7365 7710 7400 7500 7250 7207 2010 10667 14492 14045 14253 14486 14098

2011 6776 7480 7580 7320 7227 7101 2011 14179 14290 14596 14631 14642 10756

2012 7182 7680 7360 7283 7138 7331 2012 14027 14907 14926 14907 10860 14217

2013 7190 7450 7366 7142 7400 7271 2013 14140 15228 15295 11022 14270 14354

2014 7816 7487 7216 7484 7403 7334 2014 14111 15827 11251 14411 14524 14414

2015 7282 7622 7556 7477 7220 2015 11499 14580 14740 14570 14235

2016 7731 7691 7568 7314 2016 14754 14998 14741 14234

2017 7785 7635 7408 2017 15137 14859 14376

2018 7686 7467 2018 14985 14440

2019 7511 2019 14484

Table A18 PPL Electric Utilities Corporation Table A20 PPL Electric Utilities CorporationActual and Projected Residential Energy Demand (GWh) Actual and Projected Industrial Energy Demand (GWh)



2005 14218 13950 2005 9720 9750

2006 13714 14311 14099 2006 9704 9926 9968

2007 14411 14675 14392 14180 2007 9482 10136 10048 9965

2008 14419 15019 14555 14422 14469 2008 9551 10349 10084 9999 9625

2009 14218 15349 14794 14565 14584 14341 2009 8418 10577 10150 10032 9570 9401

2010 14206 15036 14702 14562 14340 14384 2010 12045 10214 10059 9228 9141 8506

2011 14356 14828 14608 14246 14390 14142 2011 8467 10084 9005 8879 8365 12151

2012 13616 14770 14350 14226 14120 13848 2012 8173 9009 8866 8211 12116 8475

2013 14295 14443 14164 14005 13658 13607 2013 8052 8864 8110 12269 8468 8133

2014 14563 14325 14161 13667 13575 13588 2014 8313 8054 12450 8501 8182 8092

2015 14335 13738 13602 13644 13647 2015 12686 8550 8281 8171 7966

2016 13896 13695 13769 13720 2016 8603 8407 8260 8066

2017 13678 13814 13732 2017 8459 8324 8129

2018 13908 13781 2018 8365 8168

2019 13790 2019 8189


Table A21 PECO Energy Company Table A23 PECO Energy CompanyActual and Projected Peak Load (MW) Actual and Projected Commercial Energy Demand (GWh) Energy Sales (GWH)



2005 8626 8320 2005 8520 8349

2006 8932 8445 8755 2006 8857 8550 8691

2007 8549 8571 8887 9066 2007 8892 8755 8864 9034

2008 8824 8700 9020 9202 8677 2008 8700 8965 9042 9215 9069

2009 7994 8831 9155 9340 8807 8956 2009 8404 9144 9223 9399 9251 8874

2010 8864 9293 9480 8940 9091 8114 2010 8472 9407 9587 9436 9052 8572

2011 8984 9622 9074 9227 8236 8786 2011 8332 9779 9625 9233 8744 8589

2012 8549 9210 9365 8359 8770 8926 2012 8063 9817 9417 8918 8705 8360

2013 8618 9506 8485 8842 8956 8529 2013 8101 9606 9097 8879 8443 7821

2014 8258 8612 8916 8987 8580 8627 2014 8025 9279 9057 8528 7790 7858

2015 8991 9018 8631 8635 8259 2015 9238 8613 7868 7936 8021

2016 9049 8683 8644 8267 2016 8699 7947 8015 8017

2017 8735 8653 8275 2017 8026 8096 8013

2018 8661 8284 2018 8177 8009

2019 8292 2019 8005

Table A22 PECO Energy Company Table A24 PECO Energy CompanyActual and Projected Residential Energy Demand (GWh) Actual and Projected Industrial Energy Demand (GWh)



2005 13469 12385 2005 15774 15449

2006 12797 12592 13738 2006 15821 15448 16089

2007 13487 12839 14013 13053 2007 16582 15448 16411 16137

2008 13317 13179 14293 13314 13757 2008 16534 15448 16739 16460 16914

2009 12893 13443 14579 13580 14032 13583 2009 15889 15757 17074 16789 17252 16864

2010 13896 14870 13852 14313 13855 13151 2010 15824 17415 17125 17597 17202 16207

2011 13686 14129 14599 14132 13414 13912 2011 15755 17467 17949 17546 16531 15991

2012 13233 14891 14415 13683 14037 13669 2012 15253 18308 17897 16861 16153 15755

2013 13241 14703 13956 14317 13806 13392 2013 15379 18254 17199 16476 15912 15481

2014 13222 14235 14604 13944 14463 13343 2014 15310 17543 16806 16071 15714 15609

2015 14896 14083 14608 13346 13288 2015 17142 16232 15949 15844 15302

2016 14224 14754 13349 13355 2016 16394 16188 16081 15294

2017 14902 13351 13422 2017 16431 16322 15287

2018 13354 13489 2018 16567 15279

2019 13556 2019 15271


Table A25 West Penn Power Company Table A27 West Penn Power CompanyActual and Projected Peak Load (MW) Actual and Projected Commercial Energy Demand (GWh) Energy Sales (GWH)



2005 3752 3702 2005 4892 4791

2006 3926 3763 3723 2006 4959 4907 4996

2007 3838 3812 3782 3813 2007 4998 5006 5092 5083

2008 3826 3845 3824 3882 3871 2008 4925 5098 5179 5179 5115

2009 3667 3866 3864 3965 3958 3910 2009 4880 5135 5249 5279 5235 5048

2010 3988 3895 4028 4036 3990 3788 2010 4983 5318 5365 5327 5160 4966

2011 4017 4078 4083 4032 3755 3757 2011 4889 5452 5387 5275 4987 4909

2012 3808 4123 4084 3771 3754 3758 2012 4849 5462 5353 5059 4931 4819

2013 3914 4120 3809 3786 3771 3784 2013 4878 5450 5169 4979 4930 4845

2014 4019 3951 3879 3840 3846 4075 2014 4956 5307 5091 5083 4909 4860

2015 3928 3903 3908 3945 3793 2015 5229 5229 4946 4897 4996

2016 3964 3980 4012 3842 2016 5343 4979 4932 4957

2017 4015 4065 3927 2017 5047 4962 5015

2018 4077 4020 2018 4962 5029

2019 4031 2019 5006

Table A26 West Penn Power Company Table A28 West Penn Power CompanyActual and Projected Residential Energy Demand (GWh) Actual and Projected Industrial Energy Demand (GWh)



2005 7088 6923 2005 8051 8027

2006 7133 7047 7164 2006 8144 8137 8283

2007 7266 7136 7289 7319 2007 8160 8220 8429 8282

2008 7172 7194 7387 7484 7481 2008 8135 8311 8543 8411 8311

2009 7101 7189 7417 7639 7654 7206 2009 7286 8313 8615 8584 8476 8440

2010 7401 7447 7761 7774 7264 7147 2010 7617 8634 8728 8699 8711 7612

2011 7349 7869 7892 7233 7104 7139 2011 7818 8766 8799 8906 7740 7833

2012 7092 7965 7248 7085 7122 7121 2012 7685 8844 9093 7936 8025 8029

2013 7318 7102 6952 7047 7149 7146 2013 7777 9246 8105 8146 8172 8087

2014 7281 7008 7073 7188 7282 7311 2014 7972 8214 8264 8334 8303 7947

2015 7148 7231 7369 7302 7383 2015 8346 8487 8542 8161 8053

2016 7281 7431 7303 7157 2016 8608 8786 8331 8492

2017 7493 7319 7244 2017 8878 8466 8903

2018 7335 7298 2018 8495 9321

2019 7303 2019 9700


Appendix B – Plant Additions and Upgrades

The following charts and maps represent PJM interconnection requests for new generating resources

located in Pennsylvania55

. The charts are segregated by renewable and non-renewable fuel sources.

Since 1999 through Dec. 31, 2014 PJM has received 737 interconnection requests totaling 131,202

MW for new generating resources or incremental additions to existing resources. This is an increase

of an additional 58 interconnection project requests totaling 10,344 MW since 2013. Currently

Pennsylvania has 4,629 MW under construction versus 2,134 MW in 2013.

Below the requests for new generating resources is a chart showing the generation deactivations for

Pennsylvania from Jan. 1, through Dec. 31, 2014.

55

See PJM 2014 RTEP, Book 5, available at http://www.pjm.com/documents/reports/rtep-documents/2014-rtep.aspx

http://www.pjm.com/documents/reports/rtep-documents/2014-rtep.aspx


PJM Generation Queue for Pennsylvania – Renewable Fuels (December 31, 2014)

Queue Project Name MW MWC Status Schedule TO Fuel Type

R43 Frackville - Hauto #3 20 4 Under Construction 6/1/2015 PPL Wind

T121 Potter-Gold 115 kV 75 15 Active 12/31/2016 PENELEC Wind

U2-015 Harwood-E. Palmerton 230 kV 100 13 Under Construction 4/30/2015 PPL Wind

U2-073 Frostburg 138 kV II 200 26 Suspended 12/15/2014 APS Wind

U2-076 Falls 10 10 Suspended 3/1/2011 PECO Methane

V3-040 Siegfried-Hauto 69 kV 10 3.8 Suspended 4/1/2014 PPL Solar

V3-041 Daleville 4 3.2 Under Construction 11/1/2011 PECO Methane

W1-045 Roxbury 23 kV 13.5 5.13 Under Construction 9/1/2016 PENELEC Solar

W1-114 Port Carbon 3 1.14 Under Construction 12/31/2013 PPL Solar

W1-115 Tamanend 3 1.14 Under Construction 6/30/2014 PPL Solar

W2-094 Straban 13.2 kV 3 1.1 Active 6/30/2012 ME Solar

W3-022 Frackville-Eldred No. 1 230 kV 150 19.5 Suspended 12/31/2016 PPL Wind

W3-099 Erie East-Erie South 230 kV 100 13 Under Construction 8/31/2017 PENELEC Wind

X2-031 Krayn 115 kV 50 6.5 Suspended 12/31/2015 PENELEC Wind

Y1-033 Penn Mar-Rock Wood 115 kV 38.3 4.98 Suspended 12/31/2015 PENELEC Wind

Y1-027 Belmon 12.5 kV 4 1.52 Suspended 12/31/2016 APS Methane

Y2-098 Freemansburg No. 1 12 kV 5 5 Under Construction 11/1/2012 PPL Methane

Y3-041 Peckville-Jackson 69 kV 62 8 Active 12/31/2017 PPL Wind

Z1-087 Glade 230 kV 508 40 Active 12/31/2015 PENELEC Hydro

Z1-088 Allegheny Dam 5 8 5 Active 10/31/2013 APS Hydro

Z1-089 Allegheny Dam 6 138 kV 9 5 Active 10/31/2013 APS Hydro

Z1-069 Gold-Sabinsville 115 kV 70 13.3 Active 12/30/2017 PENELEC Wind

Z2-009 East Hazelton-Harwood 69 kV 67.5 8.48 Active 12/31/2016 PPL Wind

Z2-013 Frostburg 138 kV 200 7 Active 12/31/2014 APS Wind

Z2-014 St. Benedict-Patton 30 5.25 Active 12/31/2015 PENELEC Wind

Z2-101 Frackville-Fishbach 69 kV 67.5 8.78 Active 12/31/2016 PPL Wind

AA1-037 Piney Hydro 34.5 kV 33.26 5.26 Active 6/1/2015 PENELEC Hydro

AA1-046 Somerset-Allegheny 115 kV 80 10.4 Active 12/1/2017 PENELEC Wind

AA1-057 Sunbury-Milton 69 kV 16 16 Active 6/1/2015 PPL Wood

AA1-077 Lackawanna 230 kV 1483 44 Active 6/1/2017 PPL Solar

AA1-085 Moshannon-Milesburg 230 kV 90 11.7 Active 10/1/2017 APS Wind

AA1-113 Frackville-Hauto 69 kV 68 8.8 Active 12/30/2017 PPL Wind

AA1-114 East Hazelton-Harwood 69 kV 68 8.8 Active 12/30/2017 PPL Wind

AA1-103 East Palmerton-Harwood 230 kV

212.5 27 Active 6/1/2016 PPL Wind

AA1-112 Westmoreland 25 kV 7.2 4 Active 8/7/2015 APS Methane

AA2-017 East Palmerton-Wagner 99 12.9 Active 12/31/2018 PPL Wind

Active: project is being studied for feasibility, impact, or facilities phase

MW: existing generation, plus new generation

MWC: new generation

UC: under construction

ISP: partially in service

IS-NC: in service, no capacity


PJM Generation Queue for Pennsylvania – Renewable Fuels (cont’d)

Location of renewable fuel queued generation interconnection requests in Pennsylvania


PJM Generation Queue for Pennsylvania – Non-Renewable Fuels (December 31, 2014)


T174 Yukon Hatfield 930 900 Under Construction 6/1/2018 APS Natural Gas

T182 TMI 230 kV 845 24 Active 1/31/2008 ME Nuclear

V4-045 Peach Bottom 2,722 320 Active 10/3/2015 PECO Nuclear

W2-028 Limerick No. 1 1,218 5 Active 12/31/2014 PECO Nuclear

W2-029 Limerick No. 2 1,218 5 Active 12/31/2014 PECO Nuclear

X1-109 E. Towanda 230 kV 850 765 Under Construction 2/29/2016 PENELEC Natural Gas

X2-012 Clinton 230 kV 850 765 Under Construction 7/30/2016 PPL Natural Gas

X2-025 Sunbury 500 kV 416 416 Under Construction 9/1/2017 PPL Natural Gas

X3-081 Upper Darby 13 kV 0.5 0 Under Construction 12/30/2012 PECO Natural Gas

X4-019 Sunbury 500 kV 643 227 Under Construction 9/1/2017 PPL Natural Gas

X4-027 Linwood 230 kV 852 35 Under Construction 6/1/2016 PECO Natural Gas

X4-048 Lackawanna 230 kV 1,000 1,000 Under Construction 12/31/2017 PPL Natural Gas

Y1-071 Burma 25 kV 6 6 Suspended 6/1/2015 APS Natural Gas

Y1-047 North Meshoppen 34.5 kV 15.4 15.4 Under Construction 4/1/2015 PENELEC Natural Gas

Y2-015 Eldred-Frackville No. 1 230 kV 344 337 Active 7/4/2015 PPL Natural Gas

Y2-042 Oxbow 25 kV 18.3 18.3 Under Construction 6/1/2015 PENELEC Natural Gas

Y2-055 Elm Street 34.5 kV 29 29 Active 7/1/2015 PENELEC Natural Gas

Y2-060 North Meshoppen 34.5 kV II 18.9 3.5 Under Construction 4/1/2015 PENELEC Natural Gas

Y2-064 Printz 606.5 19 Active 9/30/2014 PECO Natural Gas

Y2-063 Eldred-Frackville #2 230 kV 344 337 Active 12/31/2015 PPL Natural Gas

Y2-088 Garards Fort 25 kV 19.9 19.9 Suspended 6/30/2015 APS Natural Gas

Y2-089 Lackawanna 230 kV 1,370 370 Active 6/1/2015 PPL Natural Gas

Y2-080 Rhodes Lane 500 kV 1,065 1,065 Active 6/1/2017 APS Natural Gas

Y3-043 Peach Bottom 500 kV 760 760 Active 6/1/2017 PECO Natural Gas

Y3-103 Valley-Raccoon 138 kV 205 97 Active 5/1/2018 DL Natural Gas

Y3-109 Nyswaner 25 kV 19.9 19.9 Under Construction 12/31/2016 APS Natural Gas

Y3-104 Sullivan Trail-Stanton 69 kV 20 0 Active 1/1/2015 PPL Storage

Z1-015 Springdale 3, 4, 5 590 26 Active 6/1/2015 APS Natural Gas

Z1-038 Florey Knob 34.5 kV 19.9 19.9 Active 1/1/2015 PENELEC Natural Gas

Z1-055 South Bend 500 kV 714 10 Active 6/1/2016 APS Natural Gas

Z1-056 South Bend 500 kV 720 6 Active 6/1/2016 APS Natural Gas

Z1-066 Arnold 34.5 kV 19.9 0 Active 12/31/2015 PENELEC Storage

Z1-090 Sunbury 500 kV 381 381 Active 1/27/2017 PPL Natural Gas

Z1-098 Peckville-Jackson 69 kV 20 0 Suspended 1/1/2015 PPL Storage

Z1-091 Lenox 34 kV 19.9 19.9 Active 7/1/2015 PENELEC Natural Gas

Z1-092 Milan 34 kV 19.9 19.9 Active 7/1/2015 PENELEC Natural Gas

Z1-105 Emlenton 34.5 kV 19.9 19.9 Active 7/1/2015 PENELEC Natural Gas

Z1-110 Grover 34 kV 19.9 19.9 Active 7/1/2015 PENELEC Natural Gas

Z2-011 Canton 34.5 kV 19.9 19.9 Active 1/1/2016 PENELEC Natural Gas

Z2-026 North Temple 230 kV 800 800 Active 6/1/2018 ME Natural Gas

Z2-046 Susquehanna-Lackawanna 500 kV

1,050 900 Active 6/30/2018 PPL Natural Gas

Z2-064 Smith-N. Fayette 138 kV 651 600 Active 6/1/2018 APS Natural Gas

Z2-103 North Meshoppen 34.5 kV III 19.9 1 Active 4/1/2015 PENELEC Natural Gas


PJM Generation Queue for Pennsylvania – Non-Renewable Fuels (cont’d)


Z2-104 Oxbow 25 kV II 19.9 1.6 Active 6/1/2015 PENELEC Natural Gas

Z2-105 Bell-Mariana 25 kV 19.9 19.9 Under Construction 7/1/2016 APS Natural Gas

Z2-106 Washington-Bell 25 kV 19.9 19.9 Under Construction 7/1/2016 APS Natural Gas

Z2-108 Meyersdale North 115 kV 48 0 Active 12/30/2015 PENELEC Storage

Z2-107 East Carbondale-Lackawanna 69 kV

84.5 0 Active 12/30/2015 PPL Storage

AA1-015 Fayette II 625 5 Active 6/1/2015 APS Natural Gas

AA1-016 Portland 1 158 158 Active 6/1/2016 ME Oil

AA1-034 Peach Bottom 500 kV 880 120 Active 6/1/2017 PECO Natural Gas

AA1-017 Portland 2 243 243 Active 6/1/2016 ME Oil

AA1-036 Mountain 230 kV 180 180 Active 6/1/2017 UGI Natural Gas

AA1-041 Tioga 34.5 kV 19.9 19.9 Active 6/1/2016 PENELEC Natural Gas

AA1-042 Ontelaunee 574 52.5 Active 11/4/2016 ME Natural Gas

AA1-043 Ontelaunee 613 39 Active

11/4/2016 ME Natural Gas

AA1-044 Shenango-Hoytdale 345 kV 1,000 870 Active

6/1/2018 ATSI Natural Gas

AA1-045 McConnellsburg-Guilford 138 kV 400 400 Active

12/18/2015 APS Natural Gas

AA1-066 Susquehanna-Lackawanna 500 kV

1,050 80 Active 6/30/2018 PPL Natural Gas

AA1-070 Hatfield 500 kV 1,710 1,590 Active

10/1/2016 APS Coal

AA1-076 Hunterstown-Conemaugh 500 kV

1,050 1,000 Active

10/1/2019 PENELEC Natural Gas

AA1-079 Emilie 230 kV 1,342 74 Active

6/1/2015 PECO Natural Gas

AA1-082 E. Towanda 230 kV 925 75 Active


AA1-131 N. Towanda 34.5 kV 8 5 Active


AA1-106 Grover II 34.5 kV 19.9 19.9 Active


AA2-008 Sagers 230 kV 925 0 Active

7/1/2015 PPL Natural Gas

AA1-111 Moshannon-East Towanda 230 kV

926 926 Active


AA1-115 Summit-WestFall 115 kV 20 0 Active

6/1/2016 PENELEC Storage

AA1-144 East Towanda-Grover 230 kV 163 163 Active


Active: project is being studied for feasibility, impact, or facilities phase

MW: existing generation, plus new generation

MWC: new generation

UC: under construction

ISP: partially in service

IS-NC: in service, no capacity


PJM Generation Queue for Pennsylvania – Non-Renewable Fuels (cont’d)

Location of non-renewable fuel queued generation interconnection requests in Pennsylvania

2014 Generation Deactivations in Pennsylvania

Unit Capacity TO Zone Age

(Years)

Official Owner

Request Stated Deactivation

Date Actual / Projected Deactivation Date

Sunbury 3 94 PPL 62 4/14/2014* 7/18/2014 7/18/2014 Actual




Modern Power Landfill 0 MetEd 15 1/7/2014 4/8/2014 2/3/2014 Actual NUG

Note: * Indicates updated deactivation notice submitted in 2014. Original deactivation notice had previously been submitted.


Appendix C – Existing Generating Facilities

Table C-1 shows the PJM electricity supply mix summary of generating capacity by fuel type for

2014.56

The available Capacity Mix shows and the distribution of actual generation capacity utilized

for 2013 and 2014.

Table C-2 shows the most recently available data on existing generating facilities located in

Pennsylvania.57

Table C-1 Electrical Power Supply Mix

Electricity Supply Mix

PJM Region Supply Mix for 2013 & 2014

(percent)

Energy Source 2014 Capacity 2013 Capacity 2014

Generation

2013

Generation

Coal 39.7 41.3 43.5 44.3

Nuclear 17.9 18.1 34.3 34.8

Natural Gas 30.7 29.2 17.3 16.3

Hydro, Wind, & Other 5.7 5.3 4.4 4.3

Oil 6 6.2 0.4 0.2

56

See State of the Market Report, Monitoring Analytics, available at

http://www.monitoringanalytics.com/reports/PJM_State_of_the_Market/2014.shtml 57

Data reported to SNL and received by PUC staff on Aug. 7, 2015.


Table C-2 Electric Generating Facilities in Pennsylvania

County Plant Owner Ultimate ParentOwnership

(%)

Operating

Capacity

(MW)

Year First

Unit in

Service

Age Fuel Type

Adams Gettysburg Energy & Nutrient Recovery Facility

(GENRF) EnergyWorks BioPower, Inc EnergyWorks BioPower, Inc 100 3.25 2013 2 Biomass

Hamilton NRG REMA LLC NRG Energy, Inc. 100 24 1971 44 Oil

Hunterstown NRG REMA LLC NRG Energy, Inc. 100 75 1971 44 Oil

Hunterstown CC GenOn Energy Wholesale Generation, LLC NRG Energy, Inc. 100 810 2003 12 Gas

Orrtanna NRG REMA LLC NRG Energy, Inc. 100 26 1971 44 Oil

Allegheny Allegheny Energy 3, 4 and 5 Allegheny Energy Supply Company, LLC FirstEnergy Corp. 100 550 2003 12 Gas

Allegheny Energy Units 1 and 2 Allegheny Energy Supply Company, LLC FirstEnergy Corp. 100 88 1999 16 Gas

Brunot Island Orion Power Holdings, Inc. NRG Energy, Inc. 100 15 1972 43 Oil

Brunot Island CC NRG Power Midwest LP. NRG Energy, Inc. 100 235 1973 42 Gas

Cheswick NRG Power Midwest LP. NRG Energy, Inc. 100 563 1970 45 Coal

Clairton Works United States Steel Corporation United States Steel Corporation 100 27.4 1955 60 Nonrenewable

Green Mountain Solar Sun Power Electric Conservation Services Group 100 0.03 2001 14 Solar

Mon Valley Works United States Steel Corporation United States Steel Corporation 100 61.9 1943 72 Nonrenewable

PPG Monroeville Chemicals Center PPG Monroeville Chemicals Center PPG Industries, Incorporated 100 1.1 1998 17 Oil

PPG Place PPG Industries, Incorporated PPG Industries, Incorporated 100 2.3 1990 25 Oil

Armstrong Allegheny 5 Enduring Hydro LLC Enduring Hydro LLC 1

I Squared Capital I Squared Capital 99

Allegheny 6 Enduring Hydro LLC Enduring Hydro LLC 1


Allegheny 8 EIF United States Power Fund IV, L.P. Ares Owners Holdings, L.P. 94

Northbrook Energy, LLC NEO Corporation 3

Northbrook Energy, LLC 3

Allegheny 9 EIF United States Power Fund IV, L.P. Ares Owners Holdings, L.P. 94

Northbrook Energy, LLC NEO Corporation 3

Northbrook Energy, LLC 3

Armstrong County International Power America, Inc. Engie 100 676 2002 13 Gas

Keystone ArcLight Capital Partners, LLC ArcLight Capital Holdings, LLC 44.45

NRG Northeast Generating LLC NRG Energy, Inc. 3.7

NRG REMA LLC NRG Energy, Inc. 16.67

PSEG Fossil LLC Public Service Enterprise Group Incorporated 22.84

Talen Energy Corporation Talen Energy Corporation 12.34

Keystone IC Constellation Power Source Generation LLC Exelon Corporation 41.98

Duquesne Light Holdings, Inc. Duquesne Light Holdings, Inc. 2.47





Mahoning Creek Enduring Hydro LLC Enduring Hydro LLC 51


Beaver Beaver Valley FirstEnergy Nuclear Generation Corp. FirstEnergy Corp. 86.58

Ohio Edison Company FirstEnergy Corp. 4.32

Toledo Edison Company FirstEnergy Corp. 9.1

Beaver Valley Patterson Dam Enel Green Power North America, Inc. Enel Green Power S.p.A 31.7

Enel S.p.A. 68.3

Bruce Mansfield FirstEnergy Generation, LLC FirstEnergy Corp. 100 2510 1976 39 Coal

Townsend Hydro Beaver Falls Municipal Authority Beaver Falls Municipal Authority 100 4.2 1987 28 Water

Berks Altairnano PJM Li-ion Battery Storage Project AES Energy Storage, LLC AES Corporation 100 1 2009 6 Nonrenewable

Evergreen Community Power Plant Evergreen Community Power LLC Interstate Resources, Inc. 100 25 2009 6 Biomass

Morgantown Solar Park Hankin Group Hankin Group 100 1.6 2011 4 Solar

Ontelaunee Energy Center Dynegy Power, LLC Dynegy Inc. 100 599 2002 13 Gas

Pioneer Crossing Landfill Green Gas Americas, Inc. Green Gas International B.V. 100 8 2008 7 Biomass

Titus CT NRG REMA LLC NRG Energy, Inc. 100 35 1967 48 Oil

Blair Allegheny Ridge Wind Farm Infigen Energy Limited Infigen Energy Limited 100 80 2007 8 Wind

American Eagle Paper Mills Team Ten LLC Team Ten LLC 100 17.1 1929 86 Coal

Chestnut Flats Windfarm EDF Renewable Energy, Inc. EDF Group 100 38 2011 4 Wind

Juniata Locomotive Shop Norfolk Southern Corporation Norfolk Southern Corporation 100 1.2 1955 60 Coal

North Allegheny Wind Duke Energy Renewables, Inc. Duke Energy Corporation 100 70 2009 6 Wind

Sandy Ridge Wind Farm Algonquin Power Fund (America) Inc. Algonquin Power & Utilities Corp. 100 48.2 2012 3 Wind

Bradford Armenia Mountain Wind ALLETE Clean Energy ALLETE, Inc. 100 100.5 2009 6 Wind

Northern Tier Landfill Talen Renewable Energy Talen Energy Corporation 100 1.6 2009 6 Biomass

1.2 1982 33 Water

6.6 2013 2Water

1872 1976 39 Nuclear

1700 1967 48 Coal

11.2 1968 47 Oil

13.6 1990 25 Water

17.8 1990 25 Water

10 1988 27 Water

12 1988 27 Water


Table C-2 Electric Generating Facilities in Pennsylvania (cont’d)


(%)

Operating

Capacity

(MW)

Year First

Unit in

Service

Age Fuel Type

Bucks Croydon Exelon Generation Company, LLC Exelon Corporation 100 512 1974 41 Oil

Exelon-Conergy Solar Energy Center MF Mesa Lane, LLC Conergy AG 100 1.5 2008 7 Solar

Fairless Hills Steam Generating Station Exelon Generation Company, LLC Exelon Corporation 100 60 1996 19 Biomass

Fairless Works Energy Center Dominion Energy, Inc. Dominion Resources, Inc. 100 1276.4 2004 11 Gas

Falls Exelon Generation Company, LLC Exelon Corporation 100 60 1970 45 Oil

Pennsbury Generating Station Exelon Generation Company, LLC Exelon Corporation 100 5.4 1996 19 Biomass

Tullytown Landfill Gas Facility WM Renewable Energy, LLC Waste Management, Inc. 100 1.6 2013 2 Biomass

Cambria Cambria Cogeneration Gulf Pacific Power LLC Harbert Management Corporation 37.5

Harbert Power Fund V, LLC Harbert Management Corporation 12.5

UBS Global Asset Management UBS AG 1.27

UBS Group AG 48.73

Colver Power Project Constellation Power, Inc. Exelon Corporation 25

Gulf Pacific Power LLC Harbert Management Corporation 28.12

Harbert Power Fund V, LLC Harbert Management Corporation 9.38


UBS Group AG 36.55

Ebensburg Power Company Babcock & Wilcox Equity Investments, LLC Babcock & Wilcox Company 100 50 1991 24 Coal

Highland North Wind Farm Everpower Wind Holdings, Inc. Terra Firma Capital Partners Ltd. 100 75 2012 3 Wind

Highland Wind Project Everpower Wind Holdings, Inc. Terra Firma Capital Partners Ltd. 100 62.5 2009 6 Wind

Patton Wind Farm Everpower Wind Holdings, Inc. Terra Firma Capital Partners Ltd. 100 30 2012 3 Wind

Carbon PA Solar Park Project Consolidated Edison Development, Inc. Consolidated Edison, Inc. 100 10 2012 3 Solar

Panther Creek ArcLight Energy Partners Fund IV, L. P. ArcLight Capital Holdings, LLC 75

Olympus Power, LLC Olympus Holdings, LLC 25

Centre East Campus Plant Pennsylvania State University Pennsylvania State University 100 8.4 2011 4 Gas

Chester Aqua Ingrams Mill Solar Aqua Pennsylvania Inc. Aqua America Inc. 100 0.4 2009 6 Solar

Longwood Gardens Solar Plant Ecogy Pennsylvania Systems, LLC Ecogy Pennsylvania Systems, LLC 100 1.3 2010 5 Solar

Marlboro Mushrooms Solar Field Marlborough Mushrooms Marlborough Mushrooms 100 1 2011 4 Solar

Pickering Solar Aqua America Inc. Aqua America Inc. 100 1.4 2012 3 Solar

SECCRA Community Landfill Southeastern Chester County Refuse Authority Southeastern Chester County Refuse Authority 100 2.5 2007 8 Biomass

Clarion Piney Brookfield Renewable Energy Partners L.P. Brookfield Asset Management Inc. 62

Brookfield Renewable Energy Partners L.P. 38

Clearfield Shawville NRG REMA LLC NRG Energy, Inc. 100 588 1954 61 Coal

Shawville IC NRG REMA LLC NRG Energy, Inc. 100 6 1960 55 Oil

Clinton Lock Haven Talen Energy Supply, LLC Talen Energy Corporation 100 14 1969 46 Oil

Cumberland Carlisle Area School District Carlisle Area School District Carlisle Area School District 100 1.3 2010 5 Solar

Knouse Foods Solar Plant Knouse Foods Cooperative Inc Knouse Foods Cooperative Inc 100 3 2010 5 Solar

Mountain NRG REMA LLC NRG Energy, Inc. 100 50 1972 43 Oil

PPG Industries Works 6 IC Facility PPG Industries, Incorporated PPG Industries, Incorporated 100 5 1972 43 Oil

Shippensburg (Cumberland County) Landfill Talen Renewable Energy Talen Energy Corporation 100 6.4 2009 6 Biomass

West Shore Talen Energy Supply, LLC Talen Energy Corporation 100 28 1969 46 Oil

Dauphin Harrisburg Talen Energy Supply, LLC Talen Energy Corporation 100 56 1967 48 Oil

Paxton Creek Cogeneration NRG Yield, Inc. NRG Energy, Inc. 55.3

NRG Yield, Inc. 44.7

Susquehanna Resource Management Complex

(Harrisburg Facility Cogen) Lancaster County Solid Waste Management Authority Lancaster County Solid Waste Management Authority 100 21.8 1986 29 Biomass

Three Mile Island Exelon Generation Company, LLC Exelon Corporation 100 829 1974 41 Nuclear

Delaware Chester Exelon Generation Company, LLC Exelon Corporation 100 54 1969 46 Oil

Chester Operations Kimberly-Clark Corporation Kimberly-Clark Corporation 100 67 1986 29 Coal

Delaware County Resource Recovery Facility Covanta Energy Corporation Covanta Holding Corporation 100 80 1991 24 Biomass

Eddystone 3-4 Exelon Generation Company, LLC Exelon Corporation 100 760 1974 41 Oil

Eddystone CT Exelon Generation Company, LLC Exelon Corporation 100 76 1967 48 Oil

Liberty Electric Power Equipower Resources Corp. Dynegy Inc. 100 541 2002 13 Gas

Marcus Hook NextEra Energy Resources LLC NextEra Energy, Inc. 100 821.9 2004 11 Gas

Marcus Hook Cogeneration NextEra Energy Resources LLC NextEra Energy, Inc. 100 50 1987 28 Gas

Elk Johnsonburg Mill Domtar Paper Company, LLC Domtar Corp. 100 49 1993 22 Biomass

Erie Erie Coke Corporation Erie Coke Corporation Erie Coke Corporation 100 1.3 1953 62 Nonrenewable

Lakeview Gas Recovery WM Renewable Energy, LLC Waste Management, Inc. 100 6 1997 18 Biomass

Fayette Allegheny Energy Units 8 and 9 Allegheny Energy Supply Company, LLC FirstEnergy Corp. 100 88 2000 15 Gas

Fayette Energy Facility Dynegy Inc. Dynegy Inc. 100 649 2003 12 Gas

Mill Run Wind Farm NextEra Energy Resources LLC NextEra Energy, Inc. 100 15 2001 14 Wind

South Chestnut Wind Project Iberdrola Renewables, LLC Iberdrola, S.A. 100 50.4 2012 3 Wind

28 1924 91 Water

12 1986 29 Gas

110 1995 20 Coal

83 1992 23 Coal

87.5 1991 24 Coal




(%)

Operating

Capacity

(MW)

Year First

Unit in

Service

Age Fuel Type

Franklin Chambersburg Unit 12, 13 Allegheny Energy Supply Company, LLC FirstEnergy Corp. 100 88 2001 14 Gas

Falling Spring Chambersburg Borough of Chambersburg Borough of 100 7.1 1967 48 Gas

IESI Blue Ridge Landfill Talen Renewable Energy Talen Energy Corporation 100 6.4 2013 2 Biomass

Mountain View Landfill CCI Power Holdings LLC Castleton Commodities International, LLC 12.31

Energy Trading Innovations LLC 87.69

Orchard Park Chambersburg Borough of Chambersburg Borough of 100 23.2 2003 12 Gas

Huntingdon Warrior Ridge Hydroelectric American Hydro Power Co. American Hydro Power Co. 100 2.8 1985 30 Water

Indiana Conemaugh ArcLight Capital Partners, LLC ArcLight Capital Holdings, LLC 35.11





UGI Development Company UGI Corporation 5.97

Conemaugh IC Constellation Power Source Generation LLC Exelon Corporation 31.28

Duquesne Light Holdings, Inc. Duquesne Light Holdings, Inc. 3.83





UGI Development Company UGI Corporation 5.97

Homer City General Electric Capital Corporation General Electric Company 90

Metropolitan Life Insurance Company MetLife, Inc. 10

Indiana University of Pennsylvania Indiana University of Pennsylvania Indiana University of Pennsylvania 100 24 1988 27 Gas

Seward Waste Coal GenOn Energy Wholesale Generation, LLC NRG Energy, Inc. 100 521 2004 11 Coal

Lackawanna Archbald Cogeneration PEI Power Corporation Energy Transfer Partners, L.P. 100 20 1988 27 Biomass

Archbald Power Station PEI Power Corporation Energy Transfer Partners, L.P. 100 59.2 2001 14 Gas

Keystone Landfill Keystone Recovery Inc Keystone Recovery Inc 100 4.9 1995 20 Biomass

Lancaster Dart Container Corp Cogen Dart Container Corp. Dart Container Corp. 100 10.4 2012 3 Biomass

Frey Farm Landfill Talen Renewable Energy Talen Energy Corporation 100 3.2 2006 9 Biomass

Holtwood Hydroelectric Plant Talen Energy Corporation Talen Energy Corporation 100 248.7 1910 105 Water

Honey Brook Generating Station (Granger) Granger Energy of Honey Brook, L.L.C. Granger Electric Co 100 3.2 2006 9 Biomass

Keystone Solar Project Bright Plain Renewable Energy, LLC Bright Plain Renewable Energy, LLC 50

D. E. Shaw Renewable Investments, LLC D. E. Shaw & Co., L.P. 50

Lancaster County Resource Recovery Lancaster County Solid Waste Management Authority Lancaster County Solid Waste Management Authority 100 32.4 1990 25 Biomass

Martin Limestone Solar Array Plant Sunstream Energy LLC Sunstream Energy LLC 100 1 2012 3 Solar

Muddy Run Pumped Storage Facility Exelon Generation Company, LLC Exelon Corporation 100 1070 1967 48 Water

Safe Harbor Brookfield Renewable Energy Partners L.P. Brookfield Asset Management Inc. 62

Brookfield Renewable Energy Partners L.P. 38

Turkey Point Wind Project (Frey Farm Wind) Talen Renewable Energy Talen Energy Corporation 100 3.2 2011 4 Wind

Lawrence New Castle NRG Power Midwest LP. NRG Energy, Inc. 100 320 1939 76 Coal

New Castle IC Orion Power Holdings, Inc. NRG Energy, Inc. 100 2.5 1968 47 Oil

Lebanon Greater Lebanon Refuse Authority Landfill Talen Renewable Energy Talen Energy Corporation 100 3.2 2007 8 Biomass

PPL Ironwood Talen Energy Supply, LLC Talen Energy Corporation 100 660.1 2001 14 Gas

Lehigh Air Products Solar (Trexlertown Solar) Air Products Energy Enterprises, L.P. Air Products and Chemicals, Inc. 100 1.9 2011 4 Solar

Allentown Talen Energy Supply, LLC Talen Energy Corporation 100 56 1967 48 Oil

Luzerne AE Hunlock 4 Allegheny Energy Supply Company, LLC FirstEnergy Corp. 100 45 2000 15 Gas

Bear Creek Wind Project Central Hudson Enterprises Corporation Fortis Inc. 8.85

Community Energy, Inc. Community Energy, Inc. 8.85

Infigen Energy Limited Infigen Energy Limited 26.3

JPMorgan Chase & Co. JPMorgan Chase & Co. 56

Harwood Talen Energy Supply, LLC Talen Energy Corporation 100 27 1967 48 Oil

Hazle Township Flywheel Energy Storage Beacon Power LLC Rockland Capital, LLC 100 20 2013 2 Nonrenewable

Hazleton Cogeneration Starwood Energy Group Global, LLC Starwood Energy Group Global, LLC 100 152.2 1989 26 Gas

Hunlock Repowering UGI Development Company UGI Corporation 100 128.1 2011 4 Gas

Jenkins Talen Energy Supply, LLC Talen Energy Corporation 100 27.6 1969 46 Oil

MATS Wind Electric City Wind Power Corporation Electric City Wind Power Corporation 100 0.55 2008 7 Wind

Romark PA Solar Romark Logistics of PA Inc Romark Logistics of PA Inc 100 1.8 2011 4 Solar

Susquehanna Nuclear Allegheny Electric Cooperative Inc. Allegheny Electric Cooperative Inc. 10

Talen Energy Corporation Talen Energy Corporation 90

Lycoming Allenwood (PPLRE Lycoming County Landfill Project) Talen Renewable Energy Talen Energy Corporation 100 3.2 2012 3 Biomass

Laurel Hill Duke Energy Renewables, Inc. Duke Energy Corporation 100 69 2012 3 Wind

Lycoming County Landfill Project (PPL Renewable) Talen Renewable Energy Talen Energy Corporation 100 3 2012 3 Biomass

24 2006 9 Wind

2620 1983 32 Nuclear

5 2012 3 Solar

417.5 1931 84 Water

11.2 1970 45 Oil

1901.7 1969 46 Coal

14.4 2003 12 Biomass

1700 1970 45 Coal




(%)

Operating

Capacity

(MW)

Year First

Unit in

Service

Age Fuel Type

Mercer General Electric Company General Electric Company General Electric Company 100 4.3 1984 31 Oil

Monroe Pocono Raceway Solar Project Pocono International Raceway, Inc. Pocono International Raceway, Inc. 100 3 2010 5 Solar

Shawnee CT NRG REMA LLC NRG Energy, Inc. 100 24 1972 43 Oil

Montgomery 500 Virginia Solar 500 Virginia Solar, LP 500 Virginia Solar, LP 100 1 2011 4 Solar

Conshohocken -Solar Sun Power Electric Conservation Services Group 100 0.06 1999 16 Solar

Covanta Plymouth (Montenay Montgomery) Covanta Plymouth Renewable Energy L.P. Covanta Holding Corporation 100 28 1991 24 Biomass

Hill at Whitemarsh Talen Renewable Energy Talen Energy Corporation 100 1.6 2007 8 Gas

Limerick Exelon Generation Company, LLC Exelon Corporation 100 2386 1986 29 Nuclear

Moser Exelon Generation Company, LLC Exelon Corporation 100 60 1970 45 Oil

Spring House IC Plant Janssen Pharmaceuticals, Inc. Johnson & Johnson 100 3.8 2013 2 Gas

Stowe Waste Management, Inc. Waste Management, Inc. 100 3 1989 26 Biomass

West Point Facility Merck & Company, Inc. Merck & Company, Inc. 100 66 1989 26 Gas

West Point Facility IC Merck & Company, Inc. Merck & Company, Inc. 100 11 1972 43 Oil

Montour Montour Talen Energy Corporation Talen Energy Corporation 100 1516 1971 44 Coal

Northampton Bethlehem CC Conectiv Bethlehem LLC Calpine Corporation 100 1130 2002 13 Gas

Bethlehem Landfill Commonwealth Landfill Gas Commonwealth Landfill Gas 20

Pepco Energy Services, Inc. Pepco Holdings, Inc. 80

Crayola Solar Park Talen Renewable Energy Talen Energy Corporation 50

UGI Development Company UGI Corporation 50

Glendon Plant Talen Renewable Energy Talen Energy Corporation 100 3.2 2011 4 Biomass

Green Knight Energy Center Waste Management, Inc. Waste Management, Inc. 100 8.7 2001 14 Biomass

Lower Mount Bethel Talen Energy Corporation Talen Energy Corporation 100 537.5 2004 11 Gas

Martins Creek 3 and 4 Talen Energy Corporation Talen Energy Corporation 100 1700 1975 40 Gas

Martins Creek CT Talen Energy Corporation Talen Energy Corporation 100 72 1971 44 Gas

Northampton EIF Northampton LLC Ares Owners Holdings, L.P. 91.18

EIF Northampton LLC 8.82

Portland CT NRG REMA LLC NRG Energy, Inc. 100 191 1967 48 Oil

Northumberland Mount Carmel Cogeneration Mt Carmel Co-Gen, Inc. Private investors-Kenneth M. Pollock & Connie J. Pollock Rado 100 43 1990 25 Coal

Philadelphia Delaware CT Exelon Generation Company, LLC Exelon Corporation 100 74 1969 46 Oil

Grays Ferry Cogeneration Grays Ferry Cogeneration Partners Veolia Environnement SA 100 150 1997 18 Gas

Lincoln Financial Field Solar Plant NRG Renew LLC NRG Energy, Inc. 100 2.9 2013 2 Solar

Newman & Company Inc. Newman & Co Inc Newman & Co Inc 100 1.8 1964 51 Gas

Philadelphia Refinery Sunoco, Inc. Energy Transfer Partners, L.P. 100 20.6 1952 63 Nonrenewable

PWD Northeast WPCP Biogas Cogen Philadelphia Water Department Philadelphia Water Department 100 5.6 2013 2 Biomass

Richmond CT Exelon Generation Company, LLC Exelon Corporation 100 132 1973 42 Oil

Schuylkill CT Exelon Generation Company, LLC Exelon Corporation 100 38 1969 46 Oil

Southwark Exelon Generation Company, LLC Exelon Corporation 100 72 1967 48 Oil

Temple SEGF Cogen Plant Temple University Temple University 100 16 1993 22 Gas

Pike Wallenpaupack Talen Energy Corporation Talen Energy Corporation 100 44 1926 89 Water

Schuylkill Broad Mountain Landfill Facility UGI Development Company UGI Corporation 100 11 2009 6 Biomass

Fishbach Talen Energy Supply, LLC Talen Energy Corporation 100 28 1969 46 Oil

John B Rich Memorial Power Station Cogentrix Energy Power Management LLC Carlyle Group L.P. 19.55

NextEra Energy Resources LLC NextEra Energy, Inc. 5.45

Ontario Teachers' Pension Plan Board Ontario Teachers' Pension Plan Board 12.5

RI-CORP Development Inc. RI-CORP Development Inc. 50


UBS Group AG 12.18

Locust Ridge II Iberdrola Renewables, LLC Iberdrola, S.A. 100 102 2009 6 Wind

Locust Ridge Wind Farm Iberdrola Renewables, LLC Iberdrola, S.A. 100 26 2007 8 Wind

Masser Farms Realty Solar Masser Farms Realty Ltd Masser Farms Realty Ltd 100 1 2011 4 Solar

Northeastern Power Cogeneration Facility Northeastern Power Company Engie 100 52 1989 26 Coal

Pine Grove Landfill CCI Power Holdings LLC Castleton Commodities International, LLC 12.31

Energy Trading Innovations LLC 87.69

St. Nicholas Cogeneration Schuylkill Energy Resource Inc Schuylkill Energy Resource Inc 100 86 1990 25 Coal

Westwood Generating Station Olympus Westwood Funding, LLC Olympus Holdings, LLC 75

Treemont Funding, LLC ArcLight Capital Holdings, LLC 25

Snyder Sunbury CT Corona Power, LLC Corona Power, LLC 100 47.2 1971 44 Oil

Sunbury IC Corona Power, LLC Corona Power, LLC 100 5 1967 48 Oil

5.4 2008 7 Biomass

30 1987 28 Coal

112 1995 20 Coal

80 1988 27 Coal

5.4 2008 7 Biomass

2.8 2010 5 Solar




(%)

Operating

Capacity

(MW)

Year First

Unit in

Service

Age Fuel Type

Somerset Casselman Wind Iberdrola Renewables, LLC Iberdrola, S.A. 100 34.5 2007 8 Wind

Forward WindPower LLC NRG Energy Holdings Inc NRG Energy, Inc. 100 29.4 2008 7 Wind

Green Mountain Wind Farm NextEra Energy Resources LLC NextEra Energy, Inc. 100 10.4 2000 15 Wind

Lookout WindPower LLC NRG Energy Holdings Inc NRG Energy, Inc. 100 37.8 2008 7 Wind

Meyersdale Wind Project NextEra Energy Resources LLC NextEra Energy, Inc. 100 30 2003 12 Wind

Somerset Wind Project NextEra Energy Resources LLC NextEra Energy, Inc. 100 9 2001 14 Wind

Stony Creek Wind Farm EC&R Investco Mgmt, LLC E.ON SE 50

PD Alternative Investments US Inc PensionDanmark Holding AS 50

Twin Ridges Wind Farm Everpower Wind Holdings, Inc. Terra Firma Capital Partners Ltd. 100 139.4 2012 3 Wind

Tioga Blossburg NRG REMA LLC NRG Energy, Inc. 100 24 1971 44 Gas

Union Bucknell University Bucknell University Bucknell University 100 6.7 1991 24 Gas

Venango Handsome Lake Energy Constellation Power, Inc. Exelon Corporation 100 267.5 2001 14 Gas

Scrubgrass EIF United States Power Fund IV, L.P. Ares Owners Holdings, L.P. 20

Olympus Power, LLC Olympus Holdings, LLC 30

United States Power Fund III, L.P. Ares Owners Holdings, L.P. 50

Warren Kinzua Pumped Storage Project (Seneca) Harbor Hydro Holdings, LLC LS Power Group 100 451 1970 45 Water

Warren CT NRG REMA LLC NRG Energy, Inc. 100 57 1972 43 Oil

Washington Arden Landfill WM Renewable Energy, LLC Waste Management, Inc. 100 4.8 2009 6 Biomass

Wayne Waymart Wind Farm NextEra Energy Resources LLC NextEra Energy, Inc. 100 64.5 2003 12 Wind

Westmoreland Conemaugh Hydroelectric Pennsylvania Renewable Resources Pennsylvania Renewable Resources 50

PSEG Global L.L.C. Public Service Enterprise Group Incorporated 50

Wyoming Mehoopany Procter & Gamble Co. Procter & Gamble Co. 100 1.6 1984 31 Gas

Mehoopany CT Procter & Gamble Co. Procter & Gamble Co. 100 126 1985 30 Gas

Mehoopany Wind BP Wind Energy North America Inc. BP plc 50

Sempra U.S. Gas & Power, LLC Sempra Energy 50

York Brunner Island Talen Energy Corporation Talen Energy Corporation 100 1428 1961 54 Coal

Brunner Island IC Talen Energy Corporation Talen Energy Corporation 100 7.4 1967 48 Oil

P.H. Glatfelter Company - Pennsylvania P H Glatfelter Co P H Glatfelter Co 100 89.3 1948 67 Coal

Peach Bottom Exelon Generation Company, LLC Exelon Corporation 50

PSEG Nuclear LLC Public Service Enterprise Group Incorporated 50

Tolna NRG REMA LLC NRG Energy, Inc. 100 50 1972 43 Oil

Turnkey Project - GlaxoSmith GlaxoSmithKline GlaxoSmithKline 100 1.5 2010 5 Solar

2436 1974 41 Nuclear

15 1989 26Water

142.6 2012 3 Wind

52.5 2009 6 Wind

84.8 1993 22

Coal

Documents

ELECTRIC POWER OUTLOOK - PA.GovNERC Reliability Assessment The 2014 Long-Term Reliability Assessment 8 is NERC’s independent review of the 10-year reliability outlook for the North